Rep. Jay Hoffman
Filed: 10/28/2025
 
 

 
 

 
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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 
 
 
10400SB0025ham004- 23 -LRB104 16098 AAS 29398 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 
 
 
10400SB0025ham004- 24 -LRB104 16098 AAS 29398 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 
 
 
10400SB0025ham004- 25 -LRB104 16098 AAS 29398 a

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 
 
 
10400SB0025ham004- 26 -LRB104 16098 AAS 29398 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 
 
 
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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 
 
 
10400SB0025ham004- 28 -LRB104 16098 AAS 29398 a

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 
9least-cost least cost means of satisfying those objectives; 
10(2) that the utility is capable of efficiently managing and 
11supervising the construction process and has taken sufficient 
12action to ensure adequate and efficient construction and 
13supervision thereof; and (3) that the utility is capable of 
14financing the proposed construction without significant 
15adverse financial consequences for the utility or its 
16customers.
17    (b-5) As used in this subsection (b-5):
18    "Qualifying direct current applicant" means an entity that 
19seeks to provide direct current bulk transmission service for 
20the purpose of transporting electric energy in interstate 
21commerce.
22    "Qualifying direct current project" means a high voltage 
23direct current electric service line that crosses at least one 
24Illinois border, the Illinois portion of which is physically 
25located within the region of the Midcontinent Independent 
26System Operator, Inc., or its successor organization, and runs 
 
 
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1through the counties of Pike, Scott, Greene, Macoupin, 
2Montgomery, Christian, Shelby, Cumberland, and Clark, is 
3capable of transmitting electricity at voltages of 345 
4kilovolts or above, and may also include associated 
5interconnected alternating current interconnection facilities 
6in this State that are part of the proposed project and 
7reasonably necessary to connect the project with other 
8portions of the grid.
9    Notwithstanding any other provision of this Act, a 
10qualifying direct current applicant that does not own, 
11control, operate, or manage, within this State, any plant, 
12equipment, or property used or to be used for the transmission 
13of electricity at the time of its application or of the 
14Commission's order may file an application on or before 
15December 31, 2023 with the Commission pursuant to this Section 
16or Section 8-406.1 for, and the Commission may grant, a 
17certificate of public convenience and necessity to construct, 
18operate, and maintain a qualifying direct current project. The 
19qualifying direct current applicant may also include in the 
20application requests for authority under Section 8-503. The 
21Commission shall grant the application for a certificate of 
22public convenience and necessity and requests for authority 
23under Section 8-503 if it finds that the qualifying direct 
24current applicant and the proposed qualifying direct current 
25project satisfy the requirements of this subsection and 
26otherwise satisfy the criteria of this Section or Section 
 
 
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18-406.1 and the criteria of Section 8-503, as applicable to 
2the application and to the extent such criteria are not 
3superseded by the provisions of this subsection. The 
4Commission's order on the application for the certificate of 
5public convenience and necessity shall also include the 
6Commission's findings and determinations on the request or 
7requests for authority pursuant to Section 8-503. Prior to 
8filing its application under either this Section or Section 
98-406.1, the qualifying direct current applicant shall conduct 
103 public meetings in accordance with subsection (h) of this 
11Section. If the qualifying direct current applicant 
12demonstrates in its application that the proposed qualifying 
13direct current project is designed to deliver electricity to a 
14point or points on the electric transmission grid in either or 
15both the PJM Interconnection, LLC or the Midcontinent 
16Independent System Operator, Inc., or their respective 
17successor organizations, the proposed qualifying direct 
18current project shall be deemed to be, and the Commission 
19shall find it to be, for public use. If the qualifying direct 
20current applicant further demonstrates in its application that 
21the proposed transmission project has a capacity of 1,000 
22megawatts or larger and a voltage level of 345 kilovolts or 
23greater, the proposed transmission project shall be deemed to 
24satisfy, and the Commission shall find that it satisfies, the 
25criteria stated in item (1) of subsection (b) of this Section 
26or in paragraph (1) of subsection (f) of Section 8-406.1, as 
 
 
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1applicable to the application, without the taking of 
2additional evidence on these criteria. Prior to the transfer 
3of functional control of any transmission assets to a regional 
4transmission organization, a qualifying direct current 
5applicant shall request Commission approval to join a regional 
6transmission organization in an application filed pursuant to 
7this subsection (b-5) or separately pursuant to Section 7-102 
8of this Act. The Commission may grant permission to a 
9qualifying direct current applicant to join a regional 
10transmission organization if it finds that the membership, and 
11associated transfer of functional control of transmission 
12assets, benefits Illinois customers in light of the attendant 
13costs and is otherwise in the public interest. Nothing in this 
14subsection (b-5) requires a qualifying direct current 
15applicant to join a regional transmission organization. 
16Nothing in this subsection (b-5) requires the owner or 
17operator of a high voltage direct current transmission line 
18that is not a qualifying direct current project to obtain a 
19certificate of public convenience and necessity to the extent 
20it is not otherwise required by this Section 8-406 or any other 
21provision of this Act. 
22    (c) As used in this subsection (c):
23    "Decommissioning" has the meaning given to that term in 
24subsection (a) of Section 8-508.1.
25    "Nuclear power reactor" has the meaning given to that term 
26in Section 8 of the Nuclear Safety Law of 2004. 
 
 
10400SB0025ham004- 38 -LRB104 16098 AAS 29398 a

1    After the effective date of this amendatory Act of the 
2103rd General Assembly, no construction shall commence on any 
3new nuclear power reactor with a nameplate capacity of more 
4than 300 megawatts of electricity to be located within this 
5State, and no certificate of public convenience and necessity 
6or other authorization shall be issued therefor by the 
7Commission, until the Illinois Emergency Management Agency and 
8Office of Homeland Security, in consultation with the Illinois 
9Environmental Protection Agency and the Illinois Department of 
10Natural Resources, finds that the United States Government, 
11through its authorized agency, has identified and approved a 
12demonstrable technology or means for the disposal of high 
13level nuclear waste, or until such construction has been 
14specifically approved by a statute enacted by the General 
15Assembly. Beginning January 1, 2026, construction may commence 
16on a new nuclear power reactor with a nameplate capacity of 300 
17megawatts of electricity or less within this State if the 
18entity constructing the new nuclear power reactor has obtained 
19all permits, licenses, permissions, or approvals governing the 
20construction, operation, and funding of decommissioning of 
21such nuclear power reactors required by: (1) this Act; (2) any 
22rules adopted by the Illinois Emergency Management Agency and 
23Office of Homeland Security under the authority of this Act; 
24(3) any applicable federal statutes, including, but not 
25limited to, the Atomic Energy Act of 1954, the Energy 
26Reorganization Act of 1974, the Low-Level Radioactive Waste 
 
 
10400SB0025ham004- 39 -LRB104 16098 AAS 29398 a

1Policy Amendments Act of 1985, and the Energy Policy Act of 
21992; (4) any regulations promulgated or enforced by the U.S. 
3Nuclear Regulatory Commission, including, but not limited to, 
4those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of 
5the Code of Federal Regulations, as from time to time amended; 
6and (5) any other federal or State statute, rule, or 
7regulation governing the permitting, licensing, operation, or 
8decommissioning of such nuclear power reactors. None of the 
9rules developed by the Illinois Emergency Management Agency 
10and Office of Homeland Security or any other State agency, 
11board, or commission pursuant to this Act shall be construed 
12to supersede the authority of the U.S. Nuclear Regulatory 
13Commission. The changes made by this amendatory Act of the 
14103rd General Assembly shall not apply to the uprate, renewal, 
15or subsequent renewal of any license for an existing nuclear 
16power reactor that began operation prior to the effective date 
17of this amendatory Act of the 103rd General Assembly. 
18    None of the changes made in this amendatory Act of the 
19104th General Assembly this amendatory Act of the 103rd 
20General Assembly are intended to authorize the construction of 
21nuclear power plants powered by nuclear power reactors that 
22are not either: (1) small modular nuclear reactors; or (2)    
23nuclear power reactors licensed by the U.S. Nuclear Regulatory 
24Commission to operate in this State prior to the effective 
25date of this amendatory Act of the 103rd General Assembly. 
26    (d) In making its determination under subsection (b) of 
 
 
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1this Section, the Commission shall attach primary weight to 
2the cost or cost savings to the customers of the utility. The 
3Commission may consider any or all factors which will or may 
4affect such cost or cost savings, including the public 
5utility's engineering judgment regarding the materials used 
6for construction.
7    (e) The Commission may issue a temporary certificate which 
8shall remain in force not to exceed one year in cases of 
9emergency, to assure maintenance of adequate service or to 
10serve particular customers, without notice or hearing, pending 
11the determination of an application for a certificate, and may 
12by regulation exempt from the requirements of this Section 
13temporary acts or operations for which the issuance of a 
14certificate will not be required in the public interest.
15    A public utility shall not be required to obtain but may 
16apply for and obtain a certificate of public convenience and 
17necessity pursuant to this Section with respect to any matter 
18as to which it has received the authorization or order of the 
19Commission under the Electric Supplier Act, and any such 
20authorization or order granted a public utility by the 
21Commission under that Act shall as between public utilities be 
22deemed to be, and shall have except as provided in that Act the 
23same force and effect as, a certificate of public convenience 
24and necessity issued pursuant to this Section.
25    No electric cooperative shall be made or shall become a 
26party to or shall be entitled to be heard or to otherwise 
 
 
10400SB0025ham004- 41 -LRB104 16098 AAS 29398 a

1appear or participate in any proceeding initiated under this 
2Section for authorization of power plant construction and as 
3to matters as to which a remedy is available under the Electric 
4Supplier Act.
5    (f) Such certificates may be altered or modified by the 
6Commission, upon its own motion or upon application by the 
7person or corporation affected. Unless exercised within a 
8period of 2 years from the grant thereof, authority conferred 
9by a certificate of convenience and necessity issued by the 
10Commission shall be null and void.
11    No certificate of public convenience and necessity shall 
12be construed as granting a monopoly or an exclusive privilege, 
13immunity or franchise.
14    (g) A public utility that undertakes any of the actions 
15described in items (1) through (3) of this subsection (g) or 
16that has obtained approval pursuant to Section 8-406.1 of this 
17Act shall not be required to comply with the requirements of 
18this Section to the extent such requirements otherwise would 
19apply. For purposes of this Section and Section 8-406.1 of 
20this Act, "high voltage electric service line" means an 
21electric line having a design voltage of 69,000 100,000 or 
22more. For purposes of this subsection (g), a public utility 
23may do any of the following:
24        (1) replace or upgrade any existing high voltage 
25    electric service line and related facilities, 
26    notwithstanding its length or, subject to applicable 
 
 
10400SB0025ham004- 42 -LRB104 16098 AAS 29398 a

1    Article VII requirements, ownership;
2        (2) relocate any existing high voltage electric 
3    service line and related facilities, notwithstanding its 
4    length, to accommodate construction or expansion of a 
5    roadway or other transportation infrastructure; or
6        (3) construct a high voltage electric service line and 
7    related facilities that is constructed solely to serve a 
8    single customer's premises or to provide a generator 
9    interconnection to the public utility's transmission 
10    system and that will (i) pass under or over the premises 
11    owned by the customer or generator to be served; (ii) pass    
12    or under or over premises for which the customer or 
13    generator has secured the necessary right of way    
14    right-of-way; or (iii) be multi-circuited with the 
15    facilities of the public utility. 
16    (h) A public utility seeking to construct a high-voltage 
17electric service line and related facilities (Project) must 
18show that the utility has held a minimum of 2 pre-filing public 
19meetings to receive public comment concerning the Project in 
20each county where the Project is to be located, no earlier than 
216 months prior to filing an application for a certificate of 
22public convenience and necessity from the Commission. Notice 
23of the public meeting shall be published in a newspaper of 
24general circulation within the affected county once a week for 
253 consecutive weeks, beginning no earlier than one month prior 
26to the first public meeting. If the Project traverses 2 
 
 
10400SB0025ham004- 43 -LRB104 16098 AAS 29398 a

1contiguous counties and where in one county the transmission 
2line mileage and number of landowners over whose property the 
3proposed route traverses is one-fifth or less of the 
4transmission line mileage and number of such landowners of the 
5other county, then the utility may combine the 2 pre-filing 
6meetings in the county with the greater transmission line 
7mileage and affected landowners. All other requirements 
8regarding pre-filing meetings shall apply in both counties. 
9Notice of the public meeting, including a description of the 
10Project, must be provided in writing to the clerk of each 
11county where the Project is to be located. A representative of 
12the Commission shall be invited to each pre-filing public 
13meeting.
14    (h-5) A public utility seeking to construct a high-voltage 
15electric service line and related facilities must also show 
16that the Project has complied with training and competence 
17requirements under subsection (b) of Section 15 of the 
18Electric Transmission Systems Construction Standards Act. 
19    (i) For applications filed after August 18, 2015 (the 
20effective date of Public Act 99-399), the Commission shall, by 
21certified mail, notify each owner of record of land, as 
22identified in the records of the relevant county tax assessor, 
23included in the right-of-way over which the utility seeks in 
24its application to construct a high-voltage electric line of 
25the time and place scheduled for the initial hearing on the 
26public utility's application. The utility shall reimburse the 
 
 
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1Commission for the cost of the postage and supplies incurred 
2for mailing the notice.
3    (j) In determining whether to issue a certificate of 
4public convenience for a new electric generation facility to a 
5municipal power agency that is required to obtain such a 
6certificate to exercise its power of eminent domain pursuant 
7to Section 11-119.1-10 of the Illinois Municipal Code, the 
8Commission shall give due consideration to whether a 
9generation unit of similar size and type is part of the 
10municipal power agency's preferred portfolio or least-cost 
11plan for achieving renewable energy goals in its most recent 
12integrated resource plan, as described in subsection (d) of 
13Section 1-15 of the Municipal and Cooperative Electric Utility 
14Transparent Planning Act.    
15(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 
16102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 
176-1-24; 103-1066, eff. 2-20-25.)
 
18    Section 1-100. The General Not For Profit Corporation Act 
19of 1986 is amended by adding Section 108.22 as follows:
 
20    (805 ILCS 105/108.22 new)
21    Sec. 108.22. Distribution electric cooperatives.
22    (a) A distribution electric cooperative, as that term is 
23used in the Electric Supplier Act, shall maintain a publicly 
24accessible website and shall post the following documents and 
 
 
10400SB0025ham004- 45 -LRB104 16098 AAS 29398 a

1information on its website:
2        (1) The current bylaws.
3        (2) A schedule of all regular meetings, posted 
4    annually and updated as necessary.
5        (3) Planned agendas for all regular and special board 
6    meetings.
7        (4) Minutes of the regular session of each board 
8    meeting, posted within 30 days of their approval.
9        (5) A description of the director election process, 
10    including:
11            (A) eligibility requirements for director 
12        candidates;
13            (B) nomination procedures;
14            (C) voting methods and member instructions; and
15            (D) election timelines and deadlines.
16    (b) A distribution electric cooperative may include in its 
17bylaws procedures for accepting votes cast by mail or through 
18secure online voting platforms.
19    (c) Each distribution electric cooperative shall adopt 
20bylaws or written policies establishing a process that allows 
21members to address the board of directors on matters relevant 
22to the governance and operation of the cooperative.
 
23
ARTICLE 5.

 
24    Section 5-1. Short title. This Article may be cited as the 
 
 
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1Utility Data Access Act. References in this Article to "this 
2Act" mean this Article.
 
3    Section 5-5. Findings. 
4    (a) The General Assembly finds and declares that 
5optimizing energy use through whole-building utility data 
6access is in the public interest because it provides 
7consumers, building owners, utilities, and states with 
8significant economic benefits. 
9    (b) The General Assembly further finds the following:
10        (1) implementing building energy use data access 
11    legislation catalyzes the development of a strong market 
12    for building energy services which will positively impact 
13    the State's economy through significant job growth;
14        (2) improving the energy use efficiency of the 
15    existing building stock is a key strategy to help preserve 
16    the affordability of rental housing;
17        (3) energy use reductions stemming from data access 
18    can result in direct cost savings to customers and in peak 
19    load reductions that benefit all ratepayers;
20        (4) data access programs allow utilities to maximize 
21    the value of their energy use efficiency portfolio by 
22    engaging customers and directing them to energy efficiency 
23    programs and by enabling utilities to target 
24    low-performing buildings; 
25        (5) implementing building data access enables building 
 
 
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1    owners in the State to qualify for certain federal and 
2    other incentives to help them improve their assets;
3        (6) energy use data access is the foundation of a 
4    successful efficiency strategy and enables building owners 
5    to track energy use performance over time, set performance 
6    goals, and justify cost-effective energy use upgrades; and
7        (7) absent whole-building energy use data access 
8    legislation, building owners lack an efficient, defined 
9    process to obtain energy performance of their buildings in 
10    a manner that protects consumer confidentiality.
 
11    Section 5-10. Definitions. As used in this Act:
12    "Account holder" or "customer" means the person or entity 
13authorized to access or modify utility account details. 
14    "Aggregated usage data" means an aggregation of covered 
15usage data, where all data associated with a qualified 
16building or qualified property, including, but not limited to, 
17data from tenant meters and from owner meters, are combined 
18into one collective data point per utility data type, per time 
19period, and where any unique identifiers or other personal 
20information are removed or dissociated from individual meter 
21data.
22    "Aggregation threshold" means 3 or more unique 
23nonresidential qualified accounts or any combination of 5 or 
24more residential and nonresidential unique qualified accounts 
25of a property or building during the period for which data is 
 
 
10400SB0025ham004- 48 -LRB104 16098 AAS 29398 a

1requested.
2    "Benchmarking tool" means the ENERGY STAR Portfolio 
3Manager web-based tool or any prudent and cost-effective 
4alternative system or tool approved by the Commission should 
5ENERGY STAR Portfolio Manager become inoperative or no longer 
6useful to achieving the policy goals of the State of Illinois 
7that (i) enables the periodic entry of a building's energy use 
8data and other descriptive information about a building and 
9(ii) rates a building's energy efficiency against that of 
10comparable buildings nationwide.
11    "Commission" means the Illinois Commerce Commission.
12    "Covered usage data" means electric data collected from 
13one or more utility meters that reflects the quantity and 
14period of utility usage in the building, property, or portion 
15thereof.
16    "Data recipient" means:
17        (1) an owner of the property or building;
18        (2) an owner of a portion of a property with regard to 
19    covered usage data only for the utility consumption the 
20    owner or the owner's tenants, if any, pay for and consume 
21    in the owned portion;
22        (3) a tenant with regard to covered usage data only 
23    for the utility consumption the tenant or the tenant's 
24    subtenants, if any, pay for and consume in the space 
25    leased by the tenant;
26        (4) the board, in the case of a condominium or 
 
 
10400SB0025ham004- 49 -LRB104 16098 AAS 29398 a

1    cooperative ownership of the property or building; or
2        (5) an agent authorized to receive the covered usage 
3    data by anyone in paragraphs (1) through (4).
4    "Property" means:
5        (1) a single tax parcel;
6        (2) 2 or more tax parcels held in the cooperative or 
7    condominium form of ownership and governed by a single 
8    board of managers; or
9        (3) 2 or more colocated tax parcels owned or 
10    controlled by the same entity.
11    "Qualified account" means a utility account that serves 
12some or all of a building or property for which covered usage 
13data is requested and that, as affirmed by the data recipient, 
14was not controlled by the data recipient or its subsidiary 
15during the time period for which covered usage data is 
16requested.
17    "Qualified building" means a building that meets the 
18aggregation threshold.
19    "Qualified data recipient" means a data recipient with 
20respect to a qualified property or qualified building.
21    "Qualified property" means a property that meets the 
22aggregation threshold.
23    "Utility" means an entity that is an electric utility with 
24over 500,000 customers in this State and that is a public 
25utility, as defined in Section 3-105 of the Public Utilities 
26Act.
 
 
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1    "Utility data type" means electric.
 
2    Section 5-15. Utility data access. 
3    (a) Within 90 days after the effective date of this Act, 
4the Commission shall open a proceeding to establish by rule, 
5consistent with the Illinois Administrative Procedure Act and 
6the requirements of subsection (c), procedures to implement 
7the requirements of this Section. The Commission shall 
8consider industry best practices along with Illinois law, 
9rules, and Commission orders in developing the implementing 
10rules. The governing authority of a public utility district, 
11municipally owned utility, or cooperative utility may adopt a 
12rule adopted by the Commission.
13    (b) No later than 2 years after the effective date of this 
14Act, the Commission shall adopt procedures through the 
15rulemaking proceeding identified in subsection (a) whereby:
16        (1) a utility shall retain usage data in the 
17    possession of the utility on the effective date of this 
18    Act or that is subsequently generated by the utility, for 
19    a period 5 years or however long the utility retains usage 
20    data in its active billing system, whichever is longer;
21        (2) a utility shall honor an account holder's 
22    authorized request to transmit the account holder's 
23    covered usage data held by the utility to any entity 
24    designated by the account holder;
25        (3) a qualified data recipient with respect to a 
 
 
10400SB0025ham004- 51 -LRB104 16098 AAS 29398 a

1    qualified building or qualified property may request that 
2    a utility provide aggregated usage data for the qualified 
3    building or qualified property. Aggregated usage data 
4    shall include identifiers of all meters associated with 
5    the aggregate data and any other information needed for 
6    data quality assurance;
7        (4) a utility shall establish a tool or process to 
8    enable qualified data recipients to request data under 
9    this subsection. The tool or process shall meet 
10    specifications established by the Commission;
11        (5) the account holder request process and utility 
12    delivery of requested data shall be convenient, secure, 
13    and at the Commission's direction requests to the utility 
14    may be submitted exclusively through an online portal; and
15        (6) a utility shall provide updates or corrections to 
16    any previously provided usage information on the schedule 
17    established in paragraph (5) of subsection (d). Data 
18    recipients may request and receive timely revisions 
19    correcting any previously provided usage information. A 
20    utility shall also provide usage information on the 
21    schedule established in paragraph (5) of subsection (d).
22    (c) Any covered usage data that a utility provides to a 
23data recipient under this Section must meet the following 
24requirements:
25        (1) The covered usage data must be available to be 
26    requested online. A utility's validation of the 
 
 
10400SB0025ham004- 52 -LRB104 16098 AAS 29398 a

1    requester's identity shall be consistent with, and no more 
2    onerous than, the utility's then-current practices.
3        (2) The covered usage data must be provided to the 
4    data recipient in a timeframe, frequency, and format and 
5    be delivered by a method as may be determined by the 
6    Commission.
7    (d) Any covered usage data that a utility provides to a 
8data recipient under this Section must:
9        (1) be provided to the data recipient within 30 days 
10    after receiving the data recipient's valid request if the 
11    request is received after the effective date of the 
12    rulemaking identified in subsection (a) of this Section;
13        (2) for any initial upload of data to a data recipient 
14    and subject to subsection (j) of this Section, a data 
15    recipient must include all the data for the time period 
16    required in paragraph (1) of subsection (b), regardless of 
17    whether the data recipient had a business relationship 
18    with the building or property during that period;
19        (3) include all necessary data and available usage 
20    data points for data recipients to comply with reporting 
21    requirements to which they are subject, including any such 
22    usage data that the utility possesses;
23        (4) be directly uploaded to the benchmarking tool 
24    account, or delivered in another format approved by the 
25    Commission, depending on utility size under subsection 
26    (e);
 
 
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1        (5) be provided to the data recipient according to a 
2    schedule set by the Commission, but no less than monthly;
3        (6) be provided until the data recipient revokes the 
4    request for usage data or is no longer a data recipient or 
5    is no longer a qualified data recipient with respect to 
6    aggregated usage data;
7        (7) be accompanied by a list of all meters associated 
8    with the covered usage data, including, but not limited 
9    to, aggregated usage data, and shall be accompanied by any 
10    other information the Commission deems necessary including 
11    for data quality assurance; and
12        (8) be provided at no cost to the data recipient. 
13    (e) The Commission shall direct that covered usage data 
14shall be delivered to the data recipient in a standard format 
15consistent with the benchmarking tool at the data recipient's 
16request. The Commission shall direct electric utilities that 
17serve at least 500,000 customers in the State to provide 
18requested data by direct upload to the benchmarking tool and 
19associate the data with the data recipient's benchmarking tool 
20account.
21    (f) To ensure the validity and usefulness of covered usage 
22data, the utility shall provide the best available consumption 
23and other information, consistent with the utility's records 
24as presented to account holders on the utility's customer 
25portal and captured at the meter level.
26    (g) Once covered usage data has been made available to a 
 
 
10400SB0025ham004- 54 -LRB104 16098 AAS 29398 a

1duly authorized data recipient, such data may not be deleted 
2or altered by a utility system, except as is necessary to 
3correct errors or reflect rebills or is affected as part of the 
4utility's billing data retention policy. If previously 
5provided covered usage data is changed to correct errors, 
6notification must be provided to the data recipient.
7    (h) Within 180 days after the effective date of this Act, 
8the Commission shall adopt a standard form for a utility 
9account holder to authorize the sharing of the utility account 
10holder's covered usage data.
11    (i) For properties that do not meet the aggregation 
12threshold and therefore require account holder authorization, 
13the utility shall provide covered usage data to data 
14recipients upon account holder authorization, which:
15        (1) may be provided in Commission-approved form;
16        (2) may be provided in a lease agreement provision; 
17    and
18        (3) remains valid until the account holder revokes it, 
19    regardless of how the authorization is provided. 
20    (j) Access to covered usage data under this Section shall 
21be subject to any rules the Commission has adopted or may 
22choose to adopt, if the rules do not conflict with this 
23Section. 
24    (k) Except in cases where the utility has not followed 
25processes established by this Act or the utility is grossly 
26negligent, the utility shall be held harmless for third-party 
 
 
10400SB0025ham004- 55 -LRB104 16098 AAS 29398 a

1misuse of data shared under this Act and no cause of action may 
2be initiated against the utility for such subsequent misuse.
3    (l) A utility may file for cost recovery of the reasonable 
4and prudently incurred costs of providing covered usage data, 
5including establishing, operating, and maintaining data 
6aggregation and data access services, for the Commission to 
7evaluate. A utility shall make good faith efforts to secure 
8federal, State, or other relevant funding for such investments 
9in the future. Any such funding the utility receives shall be 
10deducted from future revenue requirements.
11    (m) The Commission may hire consultants and experts to 
12execute their responsibilities under this Act, with the 
13retention of those consultants and experts exempt from the 
14requirements of Section 20-10 of the Illinois Procurement 
15Code.
 
16
ARTICLE 90.

 
17    Section 90-5. The Department of Commerce and Economic 
18Opportunity Law of the Civil Administrative Code of Illinois 
19is amended by changing Section 605-1075 as follows:
 
20    (20 ILCS 605/605-1075)
21    Sec. 605-1075. Energy Transition Assistance Fund.
22    (a) The General Assembly hereby declares that management 
23of several economic development programs requires a 
 
 
10400SB0025ham004- 56 -LRB104 16098 AAS 29398 a

1consolidated funding source to improve resource efficiency. 
2The General Assembly specifically recognizes that properly 
3serving communities and workers impacted by the energy 
4transition requires that the Department of Commerce and 
5Economic Opportunity have access to the resources required for 
6the execution of the programs for workforce and contractor 
7development, just transition investments and community 
8support, and the implementation and administration of energy 
9and justice efforts by the State.
10    (b) The Department shall be responsible for the 
11administration of the Energy Transition Assistance Fund and 
12shall allocate funding on the basis of priorities established 
13in this Section. Each year, the Department shall determine the 
14available amount of resources in the Fund that can be 
15allocated to the programs identified in this Section, and 
16allocate the funding accordingly. The Department shall, to the 
17extent practical, consider both the short-term and long-term 
18costs of the programs and allocate funding so that the 
19Department is able to cover both the short-term and long-term 
20costs of these programs using projected revenue.
21    The available funding for each year shall be allocated 
22from the Fund in the following order of priority:
23        (1) for costs related to the Clean Jobs Workforce 
24    Network Program, up to $21,000,000 annually prior to June 
25    1, 2023; and $24,333,333 annually from June 1, 2023 to May 
26    30, 2026; and $26,500,000 annually thereafter;
 
 
10400SB0025ham004- 57 -LRB104 16098 AAS 29398 a

1        (2) for costs related to the Clean Energy Contractor 
2    Incubator Program, up to $21,000,000 annually prior to 
3    June 1, 2026 and up to $22,687,403 thereafter;
4        (3) for costs related to the Clean Energy Primes 
5    Contractor Accelerator Program, up to $9,000,000 annually;
6        (4) for costs related to the Barrier Reduction 
7    Program, up to $21,000,000 annually prior to June 1, 2026 
8    and up to $22,143,079 annually thereafter;
9        (5) for costs related to the Jobs and Environmental 
10    Justice Grant Program, up to $34,000,000 annually prior to 
11    June 1, 2026 and up to $41,000,000 annually thereafter;
12        (6) for costs related to the Returning Residents Clean 
13    Jobs Training Program, up to $6,000,000 annually;
14        (7) for costs related to Energy Transition Navigators, 
15    up to $6,000,000 annually prior to June 1, 2026 and up to 
16    $6,500,000 annually thereafter;
17        (8) for costs related to the Illinois Climate Works 
18    Preapprenticeship Program, up to $10,000,000 annually;
19        (9) for costs related to Energy Transition Community 
20    Support Grants, up to $40,000,000 annually;
21        (10) for costs related to the Displaced Energy Worker 
22    Dependent Scholarship, upon request by the Illinois 
23    Student Assistance Commission, up to $1,100,000 annually;
24        (11) up to $10,000,000 annually shall be transferred 
25    to the Public Utilities Fund for use by the Illinois 
26    Commerce Commission for costs of administering the changes 
 
 
10400SB0025ham004- 58 -LRB104 16098 AAS 29398 a

1    made to the Public Utilities Act by this amendatory Act of 
2    the 102nd General Assembly;
3        (12) up to $4,000,000 annually shall be transferred to 
4    the Illinois Power Agency Operations Fund for use by the 
5    Illinois Power Agency; and
6        (13) for costs related to the Clean Energy Jobs and 
7    Justice Fund, up to $1,000,000 annually.
8    The Department is authorized to utilize up to 10% of the 
9Energy Transition Assistance Fund for administrative and 
10operational expenses to implement the requirements of this 
11Act.
12    (b-5) Beginning January 1, 2028, at the direction of the 
13Department, the State Comptroller shall direct and the State 
14Treasurer shall transfer up to $84,800,000 annually into the 
15Electric Vehicle and Charging Fund from the Energy Transition 
16Assistance Fund for costs related to transportation 
17electrification programs, as described in Section 36 of the 
18Electric Vehicle Rebate Act. The Environmental Protection 
19Agency may use up to 3% of the annual allocation under this 
20subsection (b-5) for administrative and operational expenses.    
21    (c) Within 30 days after the effective date of this 
22amendatory Act of the 102nd General Assembly, each electric 
23utility serving more than 500,000 customers in the State shall 
24report to the Department its total kilowatt-hours of energy 
25delivered during the 12 months ending on the immediately 
26preceding May 31. By October 31, 2021 and each October 31 
 
 
10400SB0025ham004- 59 -LRB104 16098 AAS 29398 a

1thereafter, each electric utility serving more than 500,000 
2customers in the State shall report to the Department its 
3total kilowatt-hours of energy delivered during the 12 months 
4ending on the immediately preceding May 31.
5    (d) The Department shall, within 60 days after the 
6effective date of this amendatory Act of the 102nd General 
7Assembly:
8        (1) determine the amount necessary, but not more than 
9    $180,000,000, to meet the funding needs of the programs 
10    reliant upon the Energy Transition Assistance Fund as a 
11    revenue source for the period between the effective date 
12    of this amendatory Act of the 102nd General Assembly and 
13    December 31, 2021;
14        (2) determine, based on the kilowatt-hour deliveries 
15    for the 12 months ending May 31, 2021 reported by the 
16    electric utilities under subsection (c), the total energy 
17    transition assistance charge to be allocated to each 
18    electric utility for the period between the effective date 
19    of this amendatory Act of the 102nd General Assembly and 
20    December 31, 2021; and
21        (3) report the total energy transition assistance 
22    charge applicable until December 31, 2021 to each electric 
23    utility serving more than 500,000 customers in the State 
24    and the Illinois Commerce Commission for purposes of 
25    filing the tariff pursuant to Section 16-108.30 of the 
26    Public Utilities Act.
 
 
10400SB0025ham004- 60 -LRB104 16098 AAS 29398 a

1    (d-5) Notwithstanding subsection (d), the Department 
2shall, within 60 days after the effective date of this 
3amendatory Act of the 104th General Assembly, determine the 
4amount necessary, but not more than $192,000,000, to meet the 
5funding needs of the programs reliant upon the Energy 
6Transition Assistance Fund as a revenue source.
7    (e) The Department shall by November 30, 2021, and each 
8November 30 thereafter:
9        (1) determine the amount necessary, but not more than 
10    $180,000,000 before the effective date of this amendatory 
11    Act of the 104th General Assembly and not more than 
12    $192,000,000, plus the amount needed to fund the programs 
13    described in subsection (b-5), after the effective date of 
14    this amendatory Act of the 104th General Assembly, to meet 
15    the funding needs of the programs reliant upon the Energy 
16    Transition Assistance Fund as a revenue source for the 
17    immediately following calendar year;
18        (2) determine, based on the kilowatt-hour deliveries 
19    for the 12 months ending on the immediately preceding May 
20    31 reported to it by the electric utilities under 
21    subsection (c), the total energy transition assistance 
22    charge to be allocated to each electric utility for the 
23    immediately following calendar year; and
24        (3) report the energy transition assistance charge 
25    applicable for the immediately following calendar year to 
26    each electric utility serving more than 500,000 customers 
 
 
10400SB0025ham004- 61 -LRB104 16098 AAS 29398 a

1    in the State and the Illinois Commerce Commission for 
2    purposes of filing the tariff pursuant to Section 
3    16-108.30 of the Public Utilities Act.
4    (f) The energy transition assistance charge may not exceed 
5$192,000,000 plus the amount needed to fund the programs 
6described in subsection (b-5) $180,000,000 annually. If, at 
7the end of the calendar year, any surplus remains in the Energy 
8Transition Assistance Fund, the Department may allocate the 
9surplus from the fund in the following order of priority:
10        (1) for costs related to the development of the 
11    Stretch Energy Codes and other standards at the Capital 
12    Development Board, up to $500,000 annually, at the request 
13    of the Board;
14        (2) up to $7,000,000 annually shall be transferred to 
15    the Energy Efficiency Trust Fund and Clean Air Act Permit 
16    Fund for use by the Environmental Protection Agency for 
17    costs related to energy efficiency and weatherization, and 
18    costs of implementation, administration, and enforcement 
19    of the Clean Air Act; and
20        (3) for costs related to State fleet electrification 
21    at the Department of Central Management Services, up to 
22    $10,000,000 annually, at the request of the Department.
23(Source: P.A. 102-662, eff. 9-15-21.)
 
24    Section 90-6. The Electric Vehicle Act is amended by 
25changing Sections 45 and 55 as follows:
 
 
 
10400SB0025ham004- 62 -LRB104 16098 AAS 29398 a

1    (20 ILCS 627/45)
2    Sec. 45. Beneficial electrification.
3    (a) It is the intent of the General Assembly to decrease 
4reliance on fossil fuels, reduce pollution from the 
5transportation sector, increase access to electrification for 
6all consumers, and ensure that electric vehicle adoption and 
7increased electricity usage and demand do not place 
8significant additional burdens on the electric system and 
9create benefits for Illinois residents.
10        (1) Illinois should increase the adoption of electric 
11    vehicles in the State to 1,000,000 by 2030.
12        (2) Illinois should strive to be the best state in the 
13    nation in which to drive and manufacture electric 
14    vehicles.
15        (3) Widespread adoption of electric vehicles is 
16    necessary to electrify the transportation sector, 
17    diversify the transportation fuel mix, drive economic 
18    development, and protect air quality.
19        (4) Accelerating the adoption of electric vehicles 
20    will drive the decarbonization of Illinois' transportation 
21    sector.
22        (5) Expanded infrastructure investment will help 
23    Illinois more rapidly decarbonize the transportation 
24    sector.
25        (6) Statewide adoption of electric vehicles requires 
 
 
10400SB0025ham004- 63 -LRB104 16098 AAS 29398 a

1    increasing access to electrification for all consumers.
2        (7) Widespread adoption of electric vehicles requires 
3    increasing public access to charging equipment throughout 
4    Illinois, especially in low-income and environmental 
5    justice communities, where levels of air pollution burden 
6    tend to be higher.
7        (8) Widespread adoption of electric vehicles and 
8    charging equipment has the potential to provide customers 
9    with fuel cost savings and electric utility customers with 
10    cost-saving benefits.
11        (9) Widespread adoption of electric vehicles can 
12    improve an electric utility's electric system efficiency 
13    and operational flexibility, including the ability of the 
14    electric utility to integrate renewable energy resources 
15    and make use of off-peak generation resources that support 
16    the operation of charging equipment.
17        (10) Widespread adoption of electric vehicles should 
18    stimulate innovation, competition, and increased choices 
19    in charging equipment and networks and should also attract 
20    private capital investments and create high-quality jobs 
21    in Illinois.
22    (b) As used in this Section:
23    "Agency" means the Environmental Protection Agency.
24    "Beneficial electrification programs" means programs that 
25lower carbon dioxide emissions, replace fossil fuel use, 
26create cost savings, improve electric grid operations, reduce 
 
 
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1increases to peak demand, improve electric usage load shape, 
2and align electric usage with times of renewable generation. 
3All beneficial electrification programs shall provide for 
4incentives such that customers are induced to use electricity 
5at times of low overall system usage or at times when 
6generation from renewable energy sources is high. "Beneficial 
7electrification programs" include a portfolio of the 
8following:
9        (1) time-of-use electric rates;
10        (2) hourly pricing electric rates;
11        (3) optimized charging programs or programs that 
12    encourage charging at times beneficial to the electric 
13    grid;
14        (4) optional demand-response programs specifically 
15    related to electrification efforts;
16        (5) incentives for electrification and associated 
17    infrastructure tied to using electricity at off-peak 
18    times;
19        (6) incentives for electrification and associated 
20    infrastructure targeted to medium-duty and heavy-duty 
21    vehicles used by transit agencies;
22        (7) incentives for electrification and associated 
23    infrastructure targeted to school buses;
24        (8) incentives for electrification and associated 
25    infrastructure for medium-duty and heavy-duty government 
26    and private fleet vehicles;
 
 
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1        (9) low-income programs that provide access to 
2    electric vehicles for communities where car ownership or 
3    new car ownership is not common;
4        (10) incentives for electrification in eligible 
5    communities;
6        (11) incentives or programs to enable quicker adoption 
7    of electric vehicles by developing public charging 
8    stations in dense areas, workplaces, and low-income 
9    communities;
10        (12) incentives or programs to develop electric 
11    vehicle infrastructure that minimizes range anxiety, 
12    filling the gaps in deployment, particularly in rural 
13    areas and along highway corridors;
14        (13) incentives to encourage the development of 
15    electrification and renewable energy generation in close 
16    proximity in order to reduce grid congestion;
17        (14) offer support to low-income communities who are 
18    experiencing financial and accessibility barriers such 
19    that electric vehicle ownership is not an option; and
20        (15) other such programs as defined by the Commission.
21    "Black, indigenous, and people of color" or "BIPOC" means 
22people who are members of the groups described in 
23subparagraphs (a) through (e) of paragraph (A) of subsection 
24(1) of Section 2 of the Business Enterprise for Minorities, 
25Women, and Persons with Disabilities Act.
26    "Commission" means the Illinois Commerce Commission.
 
 
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1    "Coordinator" means the Electric Vehicle Coordinator.
2    "Electric vehicle" means a vehicle that is exclusively 
3powered by and refueled by electricity, must be plugged in to 
4charge, and is licensed to drive on public roadways. "Electric 
5vehicle" does not include electric mopeds, electric 
6off-highway vehicles, or hybrid electric vehicles and 
7extended-range electric vehicles that are also equipped with 
8conventional fueled propulsion or auxiliary engines.
9    "Electric vehicle charging station" means a station that 
10delivers electricity from a source outside an electric vehicle 
11into one or more electric vehicles.
12    "Environmental justice communities" means the definition 
13of that term based on existing methodologies and findings, 
14used and as may be updated by the Illinois Power Agency and its 
15program administrator in the Illinois Solar for All Program.
16    "Equity investment eligible community" or "eligible 
17community" means the geographic areas throughout Illinois 
18which would most benefit from equitable investments by the 
19State designed to combat discrimination and foster sustainable 
20economic growth. Specifically, "eligible community" means the 
21following areas:
22        (1) areas where residents have been historically 
23    excluded from economic opportunities, including 
24    opportunities in the energy sector, as defined pursuant to 
25    Section 10-40 of the Cannabis Regulation and Tax Act; and
26        (2) areas where residents have been historically 
 
 
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1    subject to disproportionate burdens of pollution, 
2    including pollution from the energy sector, as established 
3    by environmental justice communities as defined by the 
4    Illinois Power Agency pursuant to Illinois Power Agency 
5    Act, excluding any racial or ethnic indicators.
6    "Equity investment eligible person" or "eligible person" 
7means the persons who would most benefit from equitable 
8investments by the State designed to combat discrimination and 
9foster sustainable economic growth. Specifically, "eligible 
10person" means the following people:
11        (1) persons whose primary residence is in an equity 
12    investment eligible community;
13        (2) persons who are graduates of or currently enrolled 
14    in the foster care system; or
15        (3) persons who were formerly incarcerated.
16    "Low-income" means persons and families whose income does 
17not exceed 80% of the state median income for the current State 
18fiscal year as established by the U.S. Department of Health 
19and Human Services.
20    "Make-ready infrastructure" means the electrical and 
21construction work necessary between the distribution circuit 
22to the connection point of charging equipment.
23    "Optimized charging programs" mean programs whereby owners 
24of electric vehicles can set their vehicles to be charged 
25based on the electric system's current demand, retail or 
26wholesale market rates, incentives, the carbon or other 
 
 
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1pollution intensity of the electric generation mix, the 
2provision of grid services, efficient use of the electric 
3grid, or the availability of clean energy generation. 
4Optimized charging programs may be operated by utilities as 
5well as third parties.
6    (c) The Commission shall initiate a workshop process no 
7later than November 30, 2021 for the purpose of soliciting 
8input on the design of beneficial electrification programs 
9that the utility shall offer. The workshop shall be 
10coordinated by the Staff of the Commission, or a facilitator 
11retained by Staff, and shall be organized and facilitated in a 
12manner that encourages representation from diverse 
13stakeholders, including stakeholders representing 
14environmental justice and low-income communities, and ensures 
15equitable opportunities for participation, without requiring 
16formal intervention or representation by an attorney.
17    The stakeholder workshop process shall take into 
18consideration the benefits of electric vehicle adoption and 
19barriers to adoption, including:
20        (1) the benefit of lower bills for customers who do 
21    not charge electric vehicles;
22        (2) benefits to the distribution system from electric 
23    vehicle usage;
24        (3) the avoidance and reduction in capacity costs from 
25    optimized charging and off-peak charging;
26        (4) energy price and cost reductions;
 
 
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1        (5) environmental benefits, including greenhouse gas 
2    emission and other pollution reductions;
3        (6) current barriers to mass-market adoption, 
4    including cost of ownership and availability of charging 
5    stations;
6        (7) current barriers to increasing access among 
7    populations that have limited access to electric vehicle 
8    ownership, communities significantly impacted by 
9    transportation-related pollution, and market segments that 
10    create disproportionate pollution impacts;
11        (8) benefits of and incentives for medium-duty and 
12    heavy-duty fleet vehicle electrification;
13        (9) opportunities for eligible communities to benefit 
14    from electrification;
15        (10) geographic areas and market segments that should 
16    be prioritized for electrification infrastructure 
17    investment.
18    The workshops shall consider barriers, incentives, 
19enabling rate structures, and other opportunities for the bill 
20reduction and environmental benefits described in this 
21subsection.
22    The workshop process shall conclude no later than February 
2328, 2022. Following the workshop, the Staff of the Commission, 
24or the facilitator retained by the Staff, shall prepare and 
25submit a report, no later than March 31, 2022, to the 
26Commission that includes, but is not limited to, 
 
 
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1recommendations for transportation electrification investment 
2or incentives in the following areas:
3        (i) publicly accessible Level 2 and fast-charging 
4    stations, with a focus on bringing access to 
5    transportation electrification in densely populated areas 
6    and workplaces within eligible communities;
7        (ii) medium-duty and heavy-duty charging 
8    infrastructure used by government and private fleet 
9    vehicles that serve or travel through environmental 
10    justice or eligible communities;
11        (iii) medium-duty and heavy-duty charging 
12    infrastructure used in school bus operations, whether 
13    private or public, that primarily serve governmental or 
14    educational institutions, and also serve or travel through 
15    environmental justice or eligible communities;
16        (iv) public transit medium-duty and heavy-duty 
17    charging infrastructure, developed in consultation with 
18    public transportation agencies; and
19        (v) publicly accessible Level 2 and fast-charging 
20    stations targeted to fill gaps in deployment, particularly 
21    in rural areas and along State highway corridors.
22    The report must also identify the participants in the 
23process, program designs proposed during the process, 
24estimates of the costs and benefits of proposed programs, any 
25material issues that remained unresolved at the conclusions of 
26such process, and any recommendations for workshop process 
 
 
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1improvements. The report shall be used by the Commission to 
2inform and evaluate the cost-effectiveness cost effectiveness    
3and achievement of goals within the submitted Beneficial 
4Electrification Plans.
5    (d) No later than July 1, 2022, electric utilities serving 
6greater than 500,000 customers in the State shall file a 
7Beneficial Electrification Plan with the Illinois Commerce 
8Commission for programs that start no later than January 1, 
92023. The plan shall take into consideration recommendations 
10from the workshop report described in this Section. Within 45 
11days after the filing of the Beneficial Electrification Plan, 
12the Commission shall, with reasonable notice, open an 
13investigation to consider whether the plan meets the 
14objectives and contains the information required by this 
15Section. The Commission shall determine if the proposed plan 
16is cost-beneficial and in the public interest. When 
17considering if the plan is in the public interest and 
18determining appropriate levels of cost recovery for 
19investments and expenditures related to programs proposed by 
20an electric utility, the Commission shall consider whether the 
21investments and other expenditures are designed and reasonably 
22expected to:
23        (1) maximize total energy cost savings and rate 
24    reductions so that nonparticipants can benefit;
25        (2) address environmental justice interests by 
26    ensuring there are significant opportunities for residents 
 
 
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1    and businesses in eligible communities to directly 
2    participate in and benefit from beneficial electrification 
3    programs;
4        (3) support at least a 40% investment of make-ready 
5    infrastructure incentives to facilitate the rapid 
6    deployment of charging equipment in or serving 
7    environmental justice, low-income, and eligible 
8    communities; however, nothing in this subsection is 
9    intended to require a specific amount of spending in a 
10    particular geographic area;
11        (4) support at least a 5% investment target in 
12    electrifying medium-duty and heavy-duty school bus and 
13    diesel public transportation vehicles located in or 
14    serving environmental justice, low-income, and eligible 
15    communities in order to provide those communities and 
16    businesses with greater economic investment, 
17    transportation opportunities, and a cleaner environment so 
18    they can directly benefit from transportation 
19    electrification efforts; however, nothing in this 
20    subsection is intended to require a specific amount of 
21    spending in a particular geographic area;
22        (5) stimulate innovation, competition, private 
23    investment, and increased consumer choices in electric 
24    vehicle charging equipment and networks;
25        (6) contribute to the reduction of carbon emissions 
26    and meeting air quality standards, including improving air 
 
 
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1    quality in eligible communities who disproportionately 
2    suffer from emissions from the medium-duty and heavy-duty 
3    transportation sector;
4        (7) support the efficient and cost-effective use of 
5    the electric grid in a manner that supports electric 
6    vehicle charging operations; and
7        (8) provide resources to support private investment in 
8    charging equipment for uses in public and private charging 
9    applications, including residential, multi-family, fleet, 
10    transit, community, and corridor applications.
11    The plan shall be determined to be cost-beneficial if the 
12total cost of beneficial electrification expenditures is less 
13than the net present value of increased electricity costs 
14(defined as marginal avoided energy, avoided capacity, and 
15avoided transmission and distribution system costs) avoided by 
16programs under the plan, the net present value of reductions 
17in other customer energy costs, net revenue from all electric 
18charging in the service territory, and the societal value of 
19reduced carbon emissions and surface-level pollutants, 
20particularly in environmental justice communities. The 
21calculation of costs and benefits should be based on net 
22impacts, including the impact on customer rates.
23    The Commission shall approve, approve with modifications, 
24or reject the plan within 270 days from the date of filing. The 
25Commission may approve the plan if it finds that the plan will 
26achieve the goals described in this Section and contains the 
 
 
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1information described in this Section. Proceedings under this 
2Section shall proceed according to the rules provided by 
3Article IX of the Public Utilities Act. Information contained 
4in the approved plan shall be considered part of the record in 
5any Commission proceeding under Section 16-107.6 of the Public 
6Utilities Act, provided that a final order has not been 
7entered prior to the initial filing date. The Beneficial 
8Electrification Plan shall specifically address, at a minimum, 
9the following:
10        (i) make-ready investments to facilitate the rapid 
11    deployment of charging equipment throughout the State, 
12    facilitate the electrification of public transit and other 
13    vehicle fleets in the light-duty, medium-duty, and 
14    heavy-duty sectors, and align with Agency-issued rebates 
15    for charging equipment;
16        (ii) the development and implementation of beneficial 
17    electrification programs, including time-of-use rates and 
18    their benefit for electric vehicle users and for all 
19    customers, optimized charging programs to achieve savings 
20    identified, and new contracts and compensation for 
21    services in those programs, through signals that allow 
22    electric vehicle charging to respond to local system 
23    conditions, manage critical peak periods, serve as a 
24    demand response or peak resource, and maximize renewable 
25    energy use and integration into the grid;
26        (iii) optional commercial tariffs utilizing 
 
 
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1    alternatives to traditional demand-based rate structures 
2    to facilitate charging for light-duty, heavy-duty, and 
3    fleet electric vehicles;
4        (iv) financial and other challenges to electric 
5    vehicle usage in low-income communities, and strategies 
6    for overcoming those challenges, particularly in 
7    communities where and for people for whom car ownership is 
8    not an option;
9        (v) methods of minimizing ratepayer impacts and 
10    exempting or minimizing, to the extent possible, 
11    low-income ratepayers from the costs associated with 
12    facilitating the expansion of electric vehicle charging;
13        (vi) plans to increase access to Level 3 Public 
14    Electric Vehicle Charging Infrastructure to serve vehicles 
15    that need quicker charging times and vehicles of persons 
16    who have no other access to charging infrastructure, 
17    regardless of whether those projects participate in 
18    optimized charging programs;
19        (vii) whether to establish charging standards for type 
20    of plugs eligible for investment or incentive programs, 
21    and if so, what standards;
22        (viii) opportunities for coordination and cohesion 
23    with electric vehicle and electric vehicle charging 
24    equipment incentives established by any agency, 
25    department, board, or commission of the State, any other 
26    unit of government in the State, any national programs, or 
 
 
10400SB0025ham004- 76 -LRB104 16098 AAS 29398 a

1    any unit of the federal government;
2        (ix) ideas for the development of online tools, 
3    applications, and data sharing that provide essential 
4    information to those charging electric vehicles, and 
5    enable an automated charging response to price signals, 
6    emission signals, real-time renewable generation 
7    production, and other Commission-approved or 
8    customer-desired indicators of beneficial charging times; 
9    and
10        (x) customer education, outreach, and incentive 
11    programs that increase awareness of the programs and the 
12    benefits of transportation electrification, including 
13    direct outreach to eligible communities.
14    (e) Proceedings under this Section shall proceed according 
15to the rules provided by Article IX of the Public Utilities 
16Act. Information contained in the approved plan shall be 
17considered part of the record in any Commission proceeding 
18under Section 16-107.6 of the Public Utilities Act, provided 
19that a final order has not been entered prior to the initial 
20filing date.
21    (f) The utility shall file an update to the plan on July 1, 
222024 and every 3 years thereafter. This update shall describe 
23transportation investments made during the prior plan period, 
24investments planned for the following 24 months, and updates 
25to the information required by this Section. Beginning with 
26the first update, the    The utility shall develop the plan in 
 
 
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1conjunction with the distribution system planning process 
2described in Section 16-105.17, including incorporation of 
3stakeholder feedback from that process.
4    (g) Within 35 days after the utility files its report, the 
5Commission shall, upon its own initiative, open an 
6investigation regarding the utility's plan update to 
7investigate whether the objectives described in this Section 
8are being achieved. The Commission shall determine whether 
9investment targets should be increased based on achievement of 
10spending goals outlined in the Beneficial Electrification Plan 
11and consistency with outcomes directed in the plan stakeholder 
12workshop report. If the Commission finds, after notice and 
13hearing, that the utility's plan is materially deficient, the 
14Commission shall issue an order requiring the utility to 
15devise a corrective action plan, subject to Commission 
16approval, to bring the plan into compliance with the goals of 
17this Section. The Commission's order shall be entered within 
18270 days after the utility files its annual report. The 
19contents of a plan filed under this Section shall be available 
20for evidence in Commission proceedings. However, omission from 
21an approved plan shall not render any future utility 
22expenditure to be considered unreasonable or imprudent. The 
23Commission may, upon sufficient evidence, allow expenditures 
24that were not part of any particular distribution plan. The 
25Commission shall consider revenues from electric vehicles in 
26the utility's service territory in evaluating the retail rate 
 
 
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1impact. The retail rate impact from the development of 
2electric vehicle infrastructure shall not exceed 1% per year 
3of the total annual revenue requirements of the utility.
4    (h) In meeting the requirements of this Section, the 
5utility shall demonstrate efforts to increase the use of 
6contractors and electric vehicle charging station installers 
7that meet multiple workforce equity actions, including, but 
8not limited to:
9        (1) the business is headquartered in or the person 
10    resides in an eligible community;
11        (2) the business is majority owned by eligible person 
12    or the contractor is an eligible person;
13        (3) the business or person is certified by another 
14    municipal, State, federal, or other certification for 
15    disadvantaged businesses;
16        (4) the business or person meets the eligibility 
17    criteria for a certification program such as:
18            (A) certified under Section 2 of the Business 
19        Enterprise for Minorities, Women, and Persons with 
20        Disabilities Act;
21            (B) certified by another municipal, State, 
22        federal, or other certification for disadvantaged 
23        businesses;
24            (C) submits an affidavit showing that the vendor 
25        meets the eligibility criteria for a certification 
26        program such as those in items (A) and (B);
 
 
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1            (D) if the vendor is a nonprofit, meets any of the 
2        criteria in those in item (A), (B), or (C) with the 
3        exception that the nonprofit is not required to meet 
4        any criteria related to being a for-profit entity, or 
5        is controlled by a board of directors that consists of 
6        51% or greater individuals who are equity investment 
7        eligible persons; or
8            (E) ensuring that program implementation 
9        contractors and electric vehicle charging station 
10        installers pay employees working on electric vehicle 
11        charging installations at or above the prevailing wage 
12        rate as published by the Department of Labor.
13    Utilities shall establish reporting procedures for vendors 
14that ensure compliance with this subsection, but are 
15structured to avoid, wherever possible, placing an undue 
16administrative burden on vendors.
17    (i) Program data collection.
18        (1) In order to ensure that the benefits provided to 
19    Illinois residents and business by the clean energy 
20    economy are equitably distributed across the State, it is 
21    necessary to accurately measure the applicants and 
22    recipients of this Program. The purpose of this paragraph 
23    is to require the implementing utilities to collect all 
24    data from Program applicants and beneficiaries to track 
25    and improve equitable distribution of benefits across 
26    Illinois communities. The further purpose is to measure 
 
 
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1    any potential impact of racial discrimination on the 
2    distribution of benefits and provide the utilities the 
3    information necessary to correct any discrimination 
4    through methods consistent with State and federal law.
5        (2) The implementing utilities shall collect 
6    demographic and geographic data for each applicant and 
7    each person or business awarded benefits or contracts 
8    under this Program.
9        (3) The implementing utilities shall collect the 
10    following information from applicants and Program or 
11    procurement beneficiaries where applicable:
12            (A) demographic information, including racial or 
13        ethnic identity for real persons employed, contracted, 
14        or subcontracted through the program;
15            (B) demographic information, including racial or 
16        ethnic identity of business owners;
17            (C) geographic location of the residency of real 
18        persons or geographic location of the headquarters for 
19        businesses; and
20            (D) any other information necessary for the 
21        purpose of achieving the purpose of this paragraph.
22        (4) The utility shall publish, at least annually, 
23    aggregated information on the demographics of program and 
24    procurement applicants and beneficiaries. The utilities 
25    shall protect personal and confidential business 
26    information as necessary.
 
 
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1        (5) The utilities shall conduct a regular review 
2    process to confirm the accuracy of reported data.
3        (6) On a quarterly basis, utilities shall collect data 
4    necessary to ensure compliance with this Section and shall 
5    communicate progress toward compliance to program 
6    implementation contractors and electric vehicle charging 
7    station installation vendors.
8        (7) Utilities filing Beneficial Electrification Plans 
9    under this Section shall report annually to the Illinois 
10    Commerce Commission and the General Assembly on how 
11    hiring, contracting, job training, and other practices 
12    related to its beneficial Beneficial electrification 
13    programs enhance the diversity of vendors working on such 
14    programs. These reports must include data on vendor and 
15    employee diversity.
16    (j) Any Beneficial Electrification Plan under this Section 
17shall terminate on December 31, 2028. Beginning January 1, 
182029, utilities shall continue to support transportation 
19electrification by maintaining responsibility for the 
20following through the Multi-Year Integrated Grid Plans 
21implemented by electric utilities pursuant to Section 
2216-105.17 of the Public Utilities Act, beginning with the 
23plans that include a time period that is after January 1, 2029:
24        (i) make-ready investments and other programs that 
25    facilitate the rapid deployment of charging equipment 
26    throughout the State, especially deployment that targets 
 
 
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1    medium-duty and heavy-duty vehicle electrification and 
2    multi-unit buildings;
3        (ii) the development and implementation of (1) 
4    time-of-use rates and the benefit of the rates for 
5    electric vehicle users and for all customers, (2) 
6    optimized charging programs to achieve identified savings, 
7    and (3) new contracts and compensation for services in the 
8    optimized charging programs, through signals that allow 
9    electric vehicle charging to respond to local system 
10    conditions, manage critical peak periods, serve as a 
11    demand response or peak resource, and maximize renewable 
12    energy use and integration into the grid; and
13        (iii) commercial tariffs that utilize alternatives to 
14    traditional demand-based rate structures to facilitate 
15    charging for light-duty, heavy-duty, and fleet electric 
16    vehicles.
17    Utilities shall demonstrate methods of minimizing 
18ratepayer impacts and exempting or minimizing, to the extent 
19possible, low-income ratepayers from the costs associated with 
20facilitating the expansion of electric vehicle charging.
21    (k) (j) The provisions of this Section are severable under 
22Section 1.31 of the Statute on Statutes. 
23(Source: P.A. 102-662, eff. 9-15-21; 102-820, eff. 5-13-22; 
24103-154, eff. 6-30-23.)
 
25    (20 ILCS 627/55)
 
 
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1    Sec. 55. Charging rebate program.
2    (a) In order to substantially offset the installation 
3costs of electric vehicle charging infrastructure, beginning 
4July 1, 2022, and continuing as long as funds are available, 
5the Agency shall issue rebates, consistent with the 
6Commission-approved Beneficial Electrification Plans in 
7accordance with Section 45, to public and private 
8organizations and companies to install and maintain Level 2 or 
9Level 3 charging stations.
10    (b) The Agency shall award rebates or grants that fund up 
11to 80% of the cost of the installation of charging stations. 
12The Agency shall award additional incentives per port for 
13every charging station installed in an eligible community and 
14every charging station located to support eligible persons. In 
15order to be eligible to receive a rebate or grant, the 
16organization or company must submit an application to the 
17Agency and commit to paying the prevailing wage for the 
18installation project. The Agency shall by rule provide 
19application and other programmatic details and requirements, 
20including additional incentives for eligible communities. The 
21Agency may determine per port or project caps based on a review 
22of best practices and stakeholder engagement. The Agency shall 
23accept applications on a rolling basis and shall award rebates 
24or grants within 60 days of each application. The Agency must 
25require that any grant or rebate applicant comply with the 
26requirements of the Prevailing Wage Act for any installation 
 
 
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1of a charging station for which it seeks a rebate or grant.
2    (c) This Section is repealed on January 1, 2029.    
3(Source: P.A. 102-662, eff. 9-15-21; 102-673, eff. 11-30-21.)
 
4    Section 90-7. The Energy Transition Act is amended by 
5changing Sections 5-35, 5-40, and 5-60 as follows:
 
6    (20 ILCS 730/5-35)
7    (Section scheduled to be repealed on September 15, 2045)
8    Sec. 5-35. Energy Transition Navigators. 
9    (a) As used in this Section: 
10    "Community-based provider" means a not-for-profit 
11organization that has a history of serving low-wage or 
12low-skilled workers or individuals from economically 
13disadvantaged communities.
14    "Economically disadvantaged community" means areas of one 
15or more census tracts where the average household income does 
16not exceed 80% of the area median income.
17    (b) In order to engage eligible individuals to participate 
18in the Clean Jobs Workforce Network Program, the Illinois 
19Climate Works Preapprenticeship Program, Returning Residents 
20Clean Jobs Program, Clean Energy Contractor Incubator Program, 
21and Clean Energy Primes Contractor Accelerator Program and 
22utilize the services offered under the Energy Transition 
23Barrier Reduction Program, the Department shall, subject to 
24appropriation, contract with community-based providers to 
 
 
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1serve as Energy Transition Navigators. Energy Transition 
2Navigators shall provide education, outreach, and recruitment 
3services to equity focused populations, prioritizing 
4individuals eligible for the Clean Jobs Workforce Network 
5Program or Illinois Climate Works Preapprenticeship Program, 
6to make sure they are aware of and engaged in the statewide and 
7local workforce development systems. Additional strategies may 
8include, but are not limited to, recruitment activities and 
9events. 
10    (c) For members of equity focused populations, 
11prioritizing individuals eligible for the Clean Jobs Workforce 
12Network Program or Illinois Climate Works Preapprenticeship 
13Program, who may be interested in entrepreneurial pursuits, 
14Energy Transition Navigators may connect these individuals 
15with their area Small Business Development Center, Procurement 
16Technical Assistance Centers, or economic development 
17organization to engage in services, including, but not limited 
18to, business consulting, business planning, regulatory 
19compliance, marketing, training, accessing capital, government 
20bid, and certification assistance. 
21    (d) Energy Transition Navigators shall engage equity 
22focused populations, prioritizing individuals eligible for the 
23Clean Jobs Workforce Network Program or Illinois Climate Works 
24Preapprenticeship Program, organizations working with these 
25populations, local workforce innovation boards, and other 
26relevant stakeholders to coordinate outreach initiatives to 
 
 
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1promote information regarding programs and services offered 
2under the Clean Jobs Workforce Network Program, the Illinois 
3Climate Works Preapprenticeship Program, and the Energy 
4Transition Barrier Reduction Program. Energy Transition 
5Navigators shall provide support where reasonable to 
6individuals and entities applying for these services and 
7programs. 
8    (e) Community education, outreach, and recruitment 
9regarding the Clean Jobs Workforce Network Program, the 
10Illinois Climate Works Preapprenticeship Program, and Energy 
11Transition Barrier Reduction Program shall be targeted to the 
12equity focused populations, prioritizing individuals eligible 
13for the Clean Jobs Workforce Network Program or Illinois 
14Climate Works Preapprenticeship Program. 
15    (f) Community-based providers shall partner with 
16educational institutions or organizations working with equity 
17focused populations, local employers, labor unions, and others 
18to identify members of equity focused populations in eligible 
19communities who are unable to advance in their careers due to 
20inadequate skills. Community-based providers shall provide 
21information and consultation to equity focused populations, 
22prioritizing individuals eligible for the Clean Jobs Workforce 
23Network Program or Illinois Climate Works Preapprenticeship 
24Program, on various educational opportunities and supportive 
25services available to them.
26    (g) Community-based providers shall establish partnerships 
 
 
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1with employers, educational institutions, local economic 
2development organizations, environmental justice 
3organizations, trades groups, labor unions, and entities that 
4provide jobs, including businesses and other nonprofit 
5organizations, to target the skill needs of local industry. 
6The community-based provider shall work with local workforce 
7innovation boards and other relevant partners to develop skill 
8curriculum and career pathway support for disadvantaged 
9individuals in equity focused populations, prioritizing 
10individuals eligible for the Clean Jobs Workforce Network 
11Program or Illinois Climate Works Preapprenticeship Program, 
12that meets local employers' needs and establishes job 
13placement opportunities after training. 
14    (h) Funding for the Program is subject to appropriation 
15from the Energy Transition Assistance Fund. Priority in 
16awarding grants under this Section will be given to 
17organizations that also have experience serving populations 
18impacted by climate change.    
19    (i) Each community-based organization that receives 
20funding from the Department as an Energy Transition Navigator 
21shall provide an annual report to the Department by April 1 of 
22each calendar year. The annual report shall include the 
23following information:
24        (1) a description of the community-based 
25    organization's recruitment, screening, and training 
26    efforts; 
 
 
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1        (2) the number of individuals who apply to, 
2    participate in, and complete programs offered through the 
3    Energy Transition Workforce Program, broken down by race, 
4    gender, age, and location; and
5        (3) any other information deemed necessary by the 
6    Department.
7(Source: P.A. 102-662, eff. 9-15-21.)
 
8    (20 ILCS 730/5-40)
9    (Section scheduled to be repealed on September 15, 2045)
10    Sec. 5-40. Illinois Climate Works Preapprenticeship 
11Program. 
12    (a) Subject to appropriation, the Department shall 
13develop, and through Regional Administrators administer, the 
14Illinois Climate Works Preapprenticeship Program. The goal of 
15the Illinois Climate Works Preapprenticeship Program is to 
16create a network of hubs throughout the State that will 
17recruit, prescreen, and provide preapprenticeship skills 
18training, for which participants may attend free of charge and 
19receive a stipend, to create a qualified, diverse pipeline of 
20workers who are prepared for careers in the construction and 
21building trades and clean energy jobs opportunities therein. 
22Upon completion of the Illinois Climate Works 
23Preapprenticeship Program, the candidates will be connected to 
24and prepared to successfully complete an apprenticeship 
25program.
 
 
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1    (b) Each Climate Works Hub that receives funding from the 
2Energy Transition Assistance Fund shall provide an annual 
3report to the Illinois Works Review Panel by April 1 of each 
4calendar year. The annual report shall include the following 
5information:
6        (1) a description of the Climate Works Hub's 
7    recruitment, screening, and training efforts, including a 
8    description of training related to construction and 
9    building trades opportunities in clean energy jobs;
10        (2) the number of individuals who apply to, 
11    participate in, and complete the Climate Works Hub's 
12    program, broken down by race, gender, age, and veteran 
13    status;
14        (3) the number of the individuals referenced in 
15    paragraph (2) of this subsection who are initially 
16    accepted and placed into apprenticeship programs in the 
17    construction and building trades; and
18        (4) the number of individuals referenced in paragraph 
19    (2) of this subsection who remain in apprenticeship 
20    programs in the construction and building trades or have 
21    become journeymen one calendar year after their placement, 
22    as referenced in paragraph (3) of this subsection.
23    (c) Subject to appropriation, the Department shall provide 
24funding to 3 Climate Works Hubs throughout the State, 
25including one to the Illinois Department of Transportation 
26Region 1, one to the Illinois Department of Transportation 
 
 
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1Regions 2 and 3, and one to the Illinois Department of 
2Transportation Regions 4 and 5. An eligible organization may 
3serve as the designated Climate Works Hub for all 5 regions. 
4Climate Works Hubs shall be awarded grants in multi-year 
5increments not to exceed 36 months. Each grant shall come with 
6a one year initial term, with the Department renewing each 
7year for 2 additional years unless the grantee either declines 
8to continue or fails to meet reasonable performance measures 
9that consider apprenticeship programs timeframes. The 
10Department may take into account experience and performance as 
11a previous grantee of the Climate Works Hub as part of the 
12selection criteria for subsequent years. 
13    (d) Each Climate Works Hub that receives funding from the 
14Energy Transition Assistance Fund shall recruit, prescreen, 
15and provide preapprenticeship training to program 
16participants. Each Climate Works Hub that receives funding 
17from the Energy Transition Assistance Fund shall:
18        (1) in each Hub Site where the applicant pool allows, 
19    comply with the following:
20            (A) dedicate at least one-third of Program 
21        placements to applicants who reside in a geographic 
22        area that is impacted by economic and environmental 
23        challenges, defined as an area that is both (i) an R3 
24        Area, as defined pursuant to Section 10-40 of the 
25        Cannabis Regulation and Tax Act, and (ii) an 
26        environmental justice community, as defined by the 
 
 
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1        Illinois Power Agency under the Illinois Power Agency 
2        Act, excluding any racial or ethnic indicators used by 
3        the Agency unless and until the constitutional basis 
4        for the inclusion of the factors in determining 
5        Program admissions is established; among applicants 
6        that satisfy these criteria, preference shall be given 
7        to applicants who face barriers to employment, 
8        including low educational attainment, prior 
9        involvement with the criminal justice system, and 
10        language barriers, and applicants that are graduates 
11        of or currently enrolled in the foster care system; 
12        and
13            (B) dedicate at least two-thirds of Program 
14        placements to applicants who reside in a geographic 
15        area that is impacted by economic or environmental 
16        challenges, defined as an area that is either (i) an R3 
17        Area, as defined pursuant to Section 10-40 of the 
18        Cannabis Regulation and Tax Act, or (ii) an 
19        environmental justice community, as defined by the 
20        Illinois Power Agency in the Illinois Power Agency 
21        Act, excluding any racial or ethnic indicators used by 
22        the Agency unless and until the constitutional basis 
23        for the inclusion of the factors in determining 
24        Program admissions is established; among applicants 
25        that satisfy these criteria, preference shall be given 
26        to applicants who face barriers to employment, 
 
 
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1        including low educational attainment, prior 
2        involvement with the criminal legal system, and 
3        language barriers, and applicants that are graduates 
4        of or currently enrolled in the foster care system; 
5        and
6            (C) prioritize the remaining Program placements 
7        for the following:
8                (i) applicants who are displaced energy 
9            workers, as defined in the Energy Community 
10            Reinvestment Act;
11                (ii) persons who face barriers to employment, 
12            including low educational attainment, prior 
13            involvement with the criminal justice system, and 
14            language barriers; and
15                (iii) applicants who are graduates of or 
16            currently enrolled in the foster care system, 
17            regardless of the applicant's area of residence;    
18            Each Climate Works Hub that receives funding from 
19            the Energy Transition Assistance Fund shall:
20        (1) recruit, prescreen, and provide preapprenticeship 
21    training to equity investment eligible persons;
22        (2) provide training information related to 
23    opportunities and certifications relevant to clean energy 
24    jobs in the construction and building trades; and
25        (3) provide preapprentices with stipends they receive 
26    that may vary depending on the occupation the individual 
 
 
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1    is training for. 
2    (d-5) Priority shall be given to Climate Works Hubs that 
3have an agreement with North American Building Trades Unions 
4(NABTU) to utilize the Multi-Craft Core Curriculum or 
5successor curriculums. 
6    (e) Funding for the Program is subject to appropriation 
7from the Energy Transition Assistance Fund.
8    (f) The Department shall adopt any rules deemed necessary 
9to implement this Section.
10(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 
11102-1123, eff. 1-27-23.)
 
12    (20 ILCS 730/5-60)
13    (Section scheduled to be repealed on September 15, 2045)
14    Sec. 5-60. Jobs and Environmental Justice Grant Program. 
15    (a) In order to provide upfront capital to support the 
16development of projects, businesses, community organizations, 
17and jobs creating opportunity for historically disadvantaged 
18populations, and to provide seed capital to support community 
19ownership of renewable energy projects, the Department of 
20Commerce and Economic Opportunity shall create and administer 
21a Jobs and Environmental Justice Grant Program. The grant 
22program shall be designed to help remove barriers to project, 
23community, and business development caused by a lack of 
24capital. 
25    (b) The grant program shall provide grant awards of up to 
 
 
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1$1,000,000 per application to support the development of 
2renewable energy resources as defined in Section 1-10 of the 
3Illinois Power Agency Act, and energy efficiency measures as 
4defined in Section 8-103B of the Public Utilities Act. The 
5amount of a grant award shall be based on a project's size and 
6scope. Grants shall be provided upfront, in advance of other 
7incentives, to provide businesses, organizations, and 
8community groups with capital needed to plan, develop, and 
9execute a project. Grants shall be designed to coordinate with 
10and supplement existing incentive programs, such as the 
11Adjustable Block program, the Illinois Solar for All Program, 
12the community renewable generation projects, and renewable 
13energy procurements as described in the Illinois Power Agency 
14Act, as well as utility energy efficiency measures as 
15described in Section 8-103B of the Public Utilities Act. 
16    (c) The Jobs and Environmental Justice Grant Program shall 
17include 2 subprograms:
18        (1) the Equitable Energy Future Grant Program; and
19        (2) the Community Solar Energy Sovereignty Grant 
20    Program.
21    (d) The Equitable Energy Future Grant Program is designed 
22to provide seed funding and pre-development funding 
23opportunities for equity eligible contractors and support for 
24compliance with or fulfillment of project labor agreement and 
25prevailing wage requirements in the clean energy economy. 
26        (1) The Equitable Energy Future Grant shall be awarded 
 
 
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1    to businesses and nonprofit organizations for costs 
2    related to the following activities and project needs: 
3            (i) planning and project development, including 
4        costs for professional services such as architecture, 
5        design, engineering, auditing, consulting, and 
6        developer services; 
7            (ii) project application, deposit, and approval; 
8            (iii) purchasing and leasing of land; 
9            (iv) permitting and zoning; 
10            (v) interconnection application costs and fees, 
11        studies, and expenses; 
12            (vi) equipment and supplies; 
13            (vii) community outreach, marketing, and 
14        engagement; and
15            (viii) staff and operations expenses; and .
16            (ix) any support needed to comply with or fulfill 
17        prevailing wage and project labor agreement 
18        requirements in the clean energy economy.    
19        (2) Grants shall be awarded to projects that most 
20    effectively provide opportunities for equity eligible 
21    contractors and equity investment eligible communities, 
22    and should consider the following criteria: 
23            (i) projects that provide community benefits, 
24        which are projects that have one or more of the 
25        following characteristics: (A) greater than 50% of the 
26        project's energy provided or saved benefits low-income 
 
 
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1        residents, or (B) the project benefits not-for-profit 
2        organizations providing services to low-income 
3        households, affordable housing owners, or 
4        community-based limited liability companies providing 
5        services to low-income households; 
6            (ii) projects that are located in equity 
7        investment eligible communities; 
8            (iii) projects that provide on-the-job training; 
9            (iv) projects that contract with contractors who 
10        are participating or have participated in the Clean 
11        Energy Contractor Incubator Program, Clean Energy 
12        Primes Contractor Accelerator Program, or similar 
13        programs; and    
14            (v) projects employ a minimum of 51% of its 
15        workforce from participants and graduates of the Clean 
16        Jobs Workforce Network Program, Illinois Climate Works 
17        Preapprenticeship Program, and Returning Residents 
18        Clean Jobs Training Program; and .
19            (vi) equity eligible contractors and contractors 
20        participating in either the Clean Energy Primes 
21        Contractor Accelerator Program or the Clean Energy 
22        Contractor Incubator Program and that demonstrate 
23        support needed on a company or project-specific basis 
24        to comply with prevailing wage and project labor 
25        agreement requirements in the clean energy economy.    
26        (3) Grants shall be awarded to applicants that meet 
 
 
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1    the following criteria: 
2            (i) are equity eligible contractors per the equity 
3        accountability systems described in subsection (c-10) 
4        of Section 1-75 of the Illinois Power Agency Act, or 
5        meet the equity building criteria in paragraph (9.5) 
6        of subsection (g) of Section 8-103B of the Public 
7        Utilities Act; and 
8            (ii) provide demonstrable proof of a historical or 
9        future, and persisting, long-term partnership with the 
10        community in which the project will be located.
11    (e) The Community Solar Energy Sovereignty Grant Program 
12shall be designed to support the pre-development and 
13development of community solar projects that promote community 
14ownership and energy sovereignty. 
15        (1) Grants shall be awarded to applicants that best 
16    demonstrate the ability and intent to create community 
17    ownership and other local community benefits, including 
18    local community wealth building via community renewable 
19    generation projects. Grants shall be prioritized to 
20    applicants for whom: 
21            (i) the proposed project is located in and 
22        supporting an equity investment eligible community or 
23        communities; and
24            (ii) the proposed project provides additional 
25        benefits for participating low-income households. 
26        (2) Grant funds shall be awarded to support project 
 
 
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1    pre-development work and may also be awarded to support 
2    the development of programs and entities to assist in the 
3    long-term governance, management, and maintenance of 
4    community solar projects, such as community solar 
5    cooperatives. For example, funds may be awarded for: 
6            (i) early stage project planning; 
7            (ii) project team organization; 
8            (iii) site identification; 
9            (iv) organizing a project business model and 
10        securing financing; 
11            (v) procurement and contracting;
12            (vi) customer outreach and enrollment;
13            (vii) preliminary site assessments;
14            (viii) development of cooperative or community 
15        ownership model; and 
16            (ix) development of project models that allocate 
17        benefits to equity investment eligible communities. 
18        (3) Grant recipients shall submit reports to the 
19    Department at the end of the grant term on the activities 
20    pursued under their grant and any lessons learned for 
21    publication on the Department's website so that other 
22    energy sovereignty projects may learn from their 
23    experience. 
24        (4) Eligible applicants shall include community-based 
25    organizations, as defined in the Illinois Power Agency's 
26    long-term renewable resources procurement plan, or 
 
 
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1    technical service providers working in direct partnership 
2    with community-based organizations. 
3        (5) The amount of a grant shall be based on a projects' 
4    size and scope. Grants shall allow for a significant 
5    portion, or the entirety, of the grant value to be made 
6    upfront, in advance of other incentives, to ensure 
7    businesses and organizations have the capital needed to 
8    plan, develop, and execute a project. 
9    (f) The application process for both subprograms shall not 
10be burdensome on applicants, nor require extensive technical 
11knowledge, and shall be able to be completed on less than 4 
12standard letter-sized pages. 
13    (g) These grant subprograms may be coordinated with 
14low-interest and no-interest financing opportunities offered 
15through the Clean Energy Jobs and Justice Fund. 
16    (h) The grant subprograms may have a budget of up to 
17$41,000,000 $34,000,000 per year. No more than $8,500,000 25%    
18of the allocated budget shall go to the Community Solar Energy 
19Sovereignty Grant Program. No more than $7,000,000 of the 
20allocated budget shall go to financial assistance or technical 
21assistance to support compliance with prevailing wage and 
22project labor agreement requirements.    
23    (i) The Department shall endeavor to make expanded 
24Equitable Energy Future Grant Program grants available in line 
25with the timing of projects being constructed that have to 
26comply with newly applicable project labor agreements 
 
 
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1requirements as a result of this amendatory Act of the 104th 
2General Assembly.    
3    (j) The Department may engage contractors or provide 
4grants to nonprofit organizations in order to provide 
5technical assistance as part of this Program to equity 
6eligible contractors and contractors participating in either 
7the Clean Energy Primes Contractor Accelerator Program or 
8Clean Energy Contractor Incubator Program that need support to 
9comply with and fulfill prevailing wage and project labor 
10agreement requirements in the clean energy economy.    
11(Source: P.A. 102-662, eff. 9-15-21.)
 
12    Section 90-8. The Nuclear Safety Law of 2004 is amended by 
13changing Sections 8 and 40 as follows:
 
14    (20 ILCS 3310/8)
15    Sec. 8. Definitions. In this Act:
16    "IEMA-OHS" means the Illinois Emergency Management Agency 
17and Office of Homeland Security, or its successor agency.
18    "Director" means the Director of IEMA-OHS. 
19    "Nuclear facilities" means nuclear power plants, 
20facilities housing nuclear test and research reactors, 
21facilities for the chemical conversion of uranium, and 
22facilities for the storage of spent nuclear fuel or high-level 
23radioactive waste.
24    "Nuclear power plant" or "nuclear steam-generating 
 
 
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1facility" means a thermal power plant in which the energy 
2(heat) released by the fissioning of nuclear fuel is used to 
3boil water to produce steam.
4    "Nuclear power reactor" means an apparatus, other than an 
5atomic weapon, designed or used to sustain nuclear fission in 
6a self-supporting chain reaction.
7    "Small modular reactor" or "SMR" means an advanced nuclear 
8reactor: (1) with a rated nameplate capacity of 300 electrical 
9megawatts or less; and (2) that may be constructed and 
10operated in combination with similar reactors at a single 
11site.
12(Source: P.A. 103-569, eff. 6-1-24.)
 
13    (20 ILCS 3310/40)
14    Sec. 40. Regulation of nuclear safety.     
15    (a) The Agency shall have primary responsibility for the 
16coordination and oversight of all State governmental functions 
17concerning the regulation of nuclear power, including low 
18level waste management, environmental monitoring, 
19environmental radiochemical analysis, and transportation of 
20nuclear waste. Functions performed by the Illinois State 
21Police and the Department of Transportation in the area of 
22nuclear safety, on the effective date of this Act, may 
23continue to be performed by these agencies but under the 
24direction of the Agency. All other governmental functions 
25regulating nuclear safety shall be coordinated by the Agency.
 
 
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1    (b) (Blank). IEMA-OHS, in consultation with the Illinois 
2Environmental Protection Agency, shall adopt rules for the 
3regulation of small modular reactors. The rules shall be 
4adopted by January 1, 2026 and shall include criteria for 
5decommissioning, environmental monitoring, and emergency 
6preparedness. The rules shall include a fee structure to cover 
7IEMA-OHS costs for regulation and inspection. The fee 
8structure may include fees to cover costs of local government 
9emergency response preparedness through grants administered by 
10IEMA-OHS. None of the rules developed by the Illinois 
11Emergency Management Agency and Office of Homeland Security or 
12any other State agency, board, or commission pursuant to this 
13Act shall be construed to supersede the authority of the U.S. 
14Nuclear Regulatory Commission. The changes made by this 
15amendatory Act of the 103rd General Assembly shall not apply 
16to the uprate, renewal, or subsequent renewal of any license 
17for an existing nuclear power reactor that began operation 
18prior to the effective date of this amendatory Act of the 103rd 
19General Assembly. Any fees collected under this subsection 
20shall be deposited into the Nuclear Safety Emergency 
21Preparedness Fund created pursuant to Section 7 of the 
22Illinois Nuclear Safety Preparedness Act.
23    (c) (Blank). Consistent with federal law and policy 
24statements of and cooperative agreements with the U.S. Nuclear 
25Regulatory Commission with respect to State participation in 
26health and safety regulation of nuclear facilities, and in 
 
 
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1recognition of the role provided for the states by such laws, 
2policy statements, and cooperative agreements, IEMA-OHS may 
3develop and implement a program for inspections of small 
4modular reactors, both operational and non-operational. The 
5owner of each small modular reactor shall allow access to 
6IEMA-OHS inspectors of all premises and records of the small 
7modular reactor. The IEMA-OHS inspectors shall operate in 
8accordance with any cooperative agreements executed between 
9IEMA-OHS and the U.S. Nuclear Regulatory Commission. The 
10IEMA-OHS inspectors shall operate in accordance with the 
11security plan for the small modular reactor. IEMA-OHS programs 
12and activities under this Section shall not be inconsistent 
13with federal law.
14    (d) (Blank). IEMA-OHS shall be authorized to conduct 
15activities specified in Section 8 of the Illinois Nuclear 
16Safety Preparedness Act in regard to small modular reactors.    
17(Source: P.A. 102-133, eff. 7-23-21; 102-538, eff. 8-20-21; 
18102-813, eff. 5-13-22; 103-569, eff. 6-1-24.)
 
19    (20 ILCS 3310/75 rep.)
20    (20 ILCS 3310/90 rep.)
21    Section 90-10. The Nuclear Safety Law of 2004 is amended 
22by repealing Sections 75 and 90.
 
23    Section 90-11. The Illinois Finance Authority Act is 
24amended by changing Section 801-10 and by adding Section 
 
 
10400SB0025ham004- 104 -LRB104 16098 AAS 29398 a

1850-20 as follows:
 
2    (20 ILCS 3501/801-10)
3    Sec. 801-10. Definitions. The following terms, whenever 
4used or referred to in this Act, shall have the following 
5meanings, except in such instances where the context may 
6clearly indicate otherwise:
7    (a) The term "Authority" means the Illinois Finance 
8Authority created by this Act.
9    (b) The term "project" means an industrial project, clean 
10energy project, energy storage project, conservation project, 
11housing project, public purpose project, higher education 
12project, health facility project, cultural institution 
13project, municipal bond program project, PACE Project, 
14agricultural facility or agribusiness, and "project" may 
15include any combination of one or more of the foregoing 
16undertaken jointly by any person with one or more other 
17persons.
18    (c) The term "public purpose project" means (i) any 
19project or facility, including without limitation land, 
20buildings, structures, machinery, equipment and all other real 
21and personal property, which is authorized or required by law 
22to be acquired, constructed, improved, rehabilitated, 
23reconstructed, replaced or maintained by any unit of 
24government or any other lawful public purpose, including 
25provision of working capital, which is authorized or required 
 
 
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1by law to be undertaken by any unit of government or (ii) costs 
2incurred and other expenditures, including expenditures for 
3management, investment, or working capital costs, incurred in 
4connection with the reform, consolidation, or implementation 
5of the transition process as described in Articles 22B and 22C 
6of the Illinois Pension Code. 
7    (d) The term "industrial project" means the acquisition, 
8construction, refurbishment, creation, development or 
9redevelopment of any facility, equipment, machinery, real 
10property or personal property for use by any instrumentality 
11of the State or its political subdivisions, for use by any 
12person or institution, public or private, for profit or not 
13for profit, or for use in any trade or business, including, but 
14not limited to, any industrial, manufacturing, clean energy, 
15or commercial enterprise that is located within or outside the 
16State, provided that, with respect to a project involving 
17property located outside the State, the property must be 
18owned, operated, leased or managed by an entity located within 
19the State or an entity affiliated with an entity located 
20within the State, and which is (1) a capital project or clean 
21energy project, including, but not limited to: (i) land and 
22any rights therein, one or more buildings, structures or other 
23improvements, machinery and equipment, whether now existing or 
24hereafter acquired, and whether or not located on the same 
25site or sites; (ii) all appurtenances and facilities 
26incidental to the foregoing, including, but not limited to, 
 
 
10400SB0025ham004- 106 -LRB104 16098 AAS 29398 a

1utilities, access roads, railroad sidings, track, docking and 
2similar facilities, parking facilities, dockage, wharfage, 
3railroad roadbed, track, trestle, depot, terminal, switching 
4and signaling or related equipment, site preparation and 
5landscaping; and (iii) all non-capital costs and expenses 
6relating thereto or (2) any addition to, renovation, 
7rehabilitation or improvement of a capital project or a clean 
8energy project, or (3) any activity or undertaking within or 
9outside the State, provided that, with respect to a project 
10involving property located outside the State, the property 
11must be owned, operated, leased or managed by an entity 
12located within the State or an entity affiliated with an 
13entity located within the State, which the Authority 
14determines will aid, assist or encourage economic growth, 
15development or redevelopment within the State or any area 
16thereof, will promote the expansion, retention or 
17diversification of employment opportunities within the State 
18or any area thereof or will aid in stabilizing or developing 
19any industry or economic sector of the State economy. The term 
20"industrial project" also means the production of motion 
21pictures.
22    (e) The term "bond" or "bonds" shall include bonds, notes 
23(including bond, grant or revenue anticipation notes), 
24certificates and/or other evidences of indebtedness 
25representing an obligation to pay money, including refunding 
26bonds.
 
 
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1    (f) The terms "lease agreement" and "loan agreement" shall 
2mean: (i) an agreement whereby a project acquired by the 
3Authority by purchase, gift or lease is leased to any person, 
4corporation or unit of local government which will use or 
5cause the project to be used as a project as heretofore defined 
6upon terms providing for lease rental payments at least 
7sufficient to pay when due all principal of, interest and 
8premium, if any, on any bonds of the Authority issued with 
9respect to such project, providing for the maintenance, 
10insuring and operation of the project on terms satisfactory to 
11the Authority, providing for disposition of the project upon 
12termination of the lease term, including purchase options or 
13abandonment of the premises, and such other terms as may be 
14deemed desirable by the Authority, (ii) any agreement pursuant 
15to which the Authority agrees to loan the proceeds of its bonds 
16issued with respect to a project or other funds of the 
17Authority to any person which will use or cause the project to 
18be used as a project as heretofore defined or for any other 
19lawful purpose upon terms providing for loan repayment 
20installments at least sufficient to pay when due all principal 
21of, interest and premium, if any, on any bonds of the 
22Authority, if any, issued with respect to the project or for 
23any other lawful purpose, and providing for maintenance, 
24insurance and other matters as may be deemed desirable by the 
25Authority, or (iii) any financing or refinancing agreement 
26entered into by the Authority under subsection (aa) of Section 
 
 
10400SB0025ham004- 108 -LRB104 16098 AAS 29398 a

1801-40.
2    (g) The term "financial aid" means the expenditure of 
3Authority funds or funds provided by the Authority through the 
4issuance of its bonds, notes or other evidences of 
5indebtedness or from other sources for the development, 
6construction, acquisition or improvement of a project.
7    (h) The term "person" means an individual, corporation, 
8unit of government, business trust, estate, trust, partnership 
9or association, 2 or more persons having a joint or common 
10interest, or any other legal entity.
11    (i) The term "unit of government" means the federal 
12government, the State or unit of local government, a school 
13district, or any agency or instrumentality, office, officer, 
14department, division, bureau, commission, college or 
15university thereof.
16    (j) The term "health facility" means: (a) any public or 
17private institution, place, building, or agency required to be 
18licensed under the Hospital Licensing Act; (b) any public or 
19private institution, place, building, or agency required to be 
20licensed under the Nursing Home Care Act, the Specialized 
21Mental Health Rehabilitation Act of 2013, the ID/DD Community 
22Care Act, or the MC/DD Act; (c) any public or licensed private 
23hospital as defined in the Mental Health and Developmental 
24Disabilities Code; (d) any such facility exempted from such 
25licensure when the Director of Public Health attests that such 
26exempted facility meets the statutory definition of a facility 
 
 
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1subject to licensure; (e) any other public or private health 
2service institution, place, building, or agency which the 
3Director of Public Health attests is subject to certification 
4by the Secretary, U.S. Department of Health and Human Services 
5under the Social Security Act, as now or hereafter amended, or 
6which the Director of Public Health attests is subject to 
7standard-setting by a recognized public or voluntary 
8accrediting or standard-setting agency; (f) any public or 
9private institution, place, building or agency engaged in 
10providing one or more supporting services to a health 
11facility; (g) any public or private institution, place, 
12building or agency engaged in providing training in the 
13healing arts, including, but not limited to, schools of 
14medicine, dentistry, osteopathy, optometry, podiatry, pharmacy 
15or nursing, schools for the training of x-ray, laboratory or 
16other health care technicians and schools for the training of 
17para-professionals in the health care field; (h) any public or 
18private congregate, life or extended care or elderly housing 
19facility or any public or private home for the aged or infirm, 
20including, without limitation, any Facility as defined in the 
21Life Care Facilities Act; (i) any public or private mental, 
22emotional or physical rehabilitation facility or any public or 
23private educational, counseling, or rehabilitation facility or 
24home, for those persons with a developmental disability, those 
25who are physically ill or disabled, the emotionally disturbed, 
26those persons with a mental illness or persons with learning 
 
 
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1or similar disabilities or problems; (j) any public or private 
2alcohol, drug or substance abuse diagnosis, counseling 
3treatment or rehabilitation facility, (k) any public or 
4private institution, place, building or agency licensed by the 
5Department of Children and Family Services or which is not so 
6licensed but which the Director of Children and Family 
7Services attests provides child care, child welfare or other 
8services of the type provided by facilities subject to such 
9licensure; (l) any public or private adoption agency or 
10facility; and (m) any public or private blood bank or blood 
11center. "Health facility" also means a public or private 
12structure or structures suitable primarily for use as a 
13laboratory, laundry, nurses or interns residence or other 
14housing or hotel facility used in whole or in part for staff, 
15employees or students and their families, patients or 
16relatives of patients admitted for treatment or care in a 
17health facility, or persons conducting business with a health 
18facility, physician's facility, surgicenter, administration 
19building, research facility, maintenance, storage or utility 
20facility and all structures or facilities related to any of 
21the foregoing or required or useful for the operation of a 
22health facility, including parking or other facilities or 
23other supporting service structures required or useful for the 
24orderly conduct of such health facility. "Health facility" 
25also means, with respect to a project located outside the 
26State, any public or private institution, place, building, or 
 
 
10400SB0025ham004- 111 -LRB104 16098 AAS 29398 a

1agency which provides services similar to those described 
2above, provided that such project is owned, operated, leased 
3or managed by a participating health institution located 
4within the State, or a participating health institution 
5affiliated with an entity located within the State.
6    (k) The term "participating health institution" means (i) 
7a private corporation or association or (ii) a public entity 
8of this State, in either case authorized by the laws of this 
9State or the applicable state to provide or operate a health 
10facility as defined in this Act and which, pursuant to the 
11provisions of this Act, undertakes the financing, construction 
12or acquisition of a project or undertakes the refunding or 
13refinancing of obligations, loans, indebtedness or advances as 
14provided in this Act.
15    (l) The term "health facility project", means a specific 
16health facility work or improvement to be financed or 
17refinanced (including without limitation through reimbursement 
18of prior expenditures), acquired, constructed, enlarged, 
19remodeled, renovated, improved, furnished, or equipped, with 
20funds provided in whole or in part hereunder, any accounts 
21receivable, working capital, liability or insurance cost or 
22operating expense financing or refinancing program of a health 
23facility with or involving funds provided in whole or in part 
24hereunder, or any combination thereof.
25    (m) The term "bond resolution" means the resolution or 
26resolutions authorizing the issuance of, or providing terms 
 
 
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1and conditions related to, bonds issued under this Act and 
2includes, where appropriate, any trust agreement, trust 
3indenture, indenture of mortgage or deed of trust providing 
4terms and conditions for such bonds.
5    (n) The term "property" means any real, personal or mixed 
6property, whether tangible or intangible, or any interest 
7therein, including, without limitation, any real estate, 
8leasehold interests, appurtenances, buildings, easements, 
9equipment, furnishings, furniture, improvements, machinery, 
10rights of way, structures, accounts, contract rights or any 
11interest therein.
12    (o) The term "revenues" means, with respect to any 
13project, the rents, fees, charges, interest, principal 
14repayments, collections and other income or profit derived 
15therefrom.
16    (p) The term "higher education project" means, in the case 
17of a private institution of higher education, an educational 
18facility to be acquired, constructed, enlarged, remodeled, 
19renovated, improved, furnished, or equipped, or any 
20combination thereof.
21    (q) The term "cultural institution project" means, in the 
22case of a cultural institution, a cultural facility to be 
23acquired, constructed, enlarged, remodeled, renovated, 
24improved, furnished, or equipped, or any combination thereof.
25    (r) The term "educational facility" means any property 
26located within the State, or any property located outside the 
 
 
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1State, provided that, if the property is located outside the 
2State, it must be owned, operated, leased or managed by an 
3entity located within the State or an entity affiliated with 
4an entity located within the State, in each case constructed 
5or acquired before or after the effective date of this Act, 
6which is or will be, in whole or in part, suitable for the 
7instruction, feeding, recreation or housing of students, the 
8conducting of research or other work of a private institution 
9of higher education, the use by a private institution of 
10higher education in connection with any educational, research 
11or related or incidental activities then being or to be 
12conducted by it, or any combination of the foregoing, 
13including, without limitation, any such property suitable for 
14use as or in connection with any one or more of the following: 
15an academic facility, administrative facility, agricultural 
16facility, assembly hall, athletic facility, auditorium, 
17boating facility, campus, communication facility, computer 
18facility, continuing education facility, classroom, dining 
19hall, dormitory, exhibition hall, fire fighting facility, fire 
20prevention facility, food service and preparation facility, 
21gymnasium, greenhouse, health care facility, hospital, 
22housing, instructional facility, laboratory, library, 
23maintenance facility, medical facility, museum, offices, 
24parking area, physical education facility, recreational 
25facility, research facility, stadium, storage facility, 
26student union, study facility, theatre or utility.
 
 
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1    (s) The term "cultural facility" means any property 
2located within the State, or any property located outside the 
3State, provided that, if the property is located outside the 
4State, it must be owned, operated, leased or managed by an 
5entity located within the State or an entity affiliated with 
6an entity located within the State, in each case constructed 
7or acquired before or after the effective date of this Act, 
8which is or will be, in whole or in part, suitable for the 
9particular purposes or needs of a cultural institution, 
10including, without limitation, any such property suitable for 
11use as or in connection with any one or more of the following: 
12an administrative facility, aquarium, assembly hall, 
13auditorium, botanical garden, exhibition hall, gallery, 
14greenhouse, library, museum, scientific laboratory, theater or 
15zoological facility, and shall also include, without 
16limitation, books, works of art or music, animal, plant or 
17aquatic life or other items for display, exhibition or 
18performance. The term "cultural facility" includes buildings 
19on the National Register of Historic Places which are owned or 
20operated by nonprofit entities.
21    (t) "Private institution of higher education" means a 
22not-for-profit educational institution which is not owned by 
23the State or any political subdivision, agency, 
24instrumentality, district or municipality thereof, which is 
25authorized by law to provide a program of education beyond the 
26high school level and which:
 
 
10400SB0025ham004- 115 -LRB104 16098 AAS 29398 a

1        (1) Admits as regular students only individuals having 
2    a certificate of graduation from a high school, or the 
3    recognized equivalent of such a certificate;
4        (2) Provides an educational program for which it 
5    awards a bachelor's degree, or provides an educational 
6    program, admission into which is conditioned upon the 
7    prior attainment of a bachelor's degree or its equivalent, 
8    for which it awards a postgraduate degree, or provides not 
9    less than a 2-year program which is acceptable for full 
10    credit toward such a degree, or offers a 2-year program in 
11    engineering, mathematics, or the physical or biological 
12    sciences which is designed to prepare the student to work 
13    as a technician and at a semiprofessional level in 
14    engineering, scientific, or other technological fields 
15    which require the understanding and application of basic 
16    engineering, scientific, or mathematical principles or 
17    knowledge;
18        (3) Is accredited by a nationally recognized 
19    accrediting agency or association or, if not so 
20    accredited, is an institution whose credits are accepted, 
21    on transfer, by not less than 3 institutions which are so 
22    accredited, for credit on the same basis as if transferred 
23    from an institution so accredited, and holds an unrevoked 
24    certificate of approval under the Private College Act from 
25    the Board of Higher Education, or is qualified as a 
26    "degree granting institution" under the Academic Degree 
 
 
10400SB0025ham004- 116 -LRB104 16098 AAS 29398 a

1    Act; and
2        (4) Does not discriminate in the admission of students 
3    on the basis of race or color. "Private institution of 
4    higher education" also includes any "academic 
5    institution".
6    (u) The term "academic institution" means any 
7not-for-profit institution which is not owned by the State or 
8any political subdivision, agency, instrumentality, district 
9or municipality thereof, which institution engages in, or 
10facilitates academic, scientific, educational or professional 
11research or learning in a field or fields of study taught at a 
12private institution of higher education. Academic institutions 
13include, without limitation, libraries, archives, academic, 
14scientific, educational or professional societies, 
15institutions, associations or foundations having such 
16purposes.
17    (v) The term "cultural institution" means any 
18not-for-profit institution which is not owned by the State or 
19any political subdivision, agency, instrumentality, district 
20or municipality thereof, which institution engages in the 
21cultural, intellectual, scientific, educational or artistic 
22enrichment of the people of the State. Cultural institutions 
23include, without limitation, aquaria, botanical societies, 
24historical societies, libraries, museums, performing arts 
25associations or societies, scientific societies and zoological 
26societies. 
 
 
10400SB0025ham004- 117 -LRB104 16098 AAS 29398 a

1    (w) The term "affiliate" means, with respect to financing 
2of an agricultural facility or an agribusiness, any lender, 
3any person, firm or corporation controlled by, or under common 
4control with, such lender, and any person, firm or corporation 
5controlling such lender.
6    (x) The term "agricultural facility" means land, any 
7building or other improvement thereon or thereto, and any 
8personal properties deemed necessary or suitable for use, 
9whether or not now in existence, in farming, ranching, the 
10production of agricultural commodities (including, without 
11limitation, the products of aquaculture, hydroponics and 
12silviculture) or the treating, processing or storing of such 
13agricultural commodities when such activities are customarily 
14engaged in by farmers as a part of farming and which land, 
15building, improvement or personal property is located within 
16the State, or is located outside the State, provided that, if 
17such property is located outside the State, it must be owned, 
18operated, leased, or managed by an entity located within the 
19State or an entity affiliated with an entity located within 
20the State.
21    (y) The term "lender" with respect to financing of an 
22agricultural facility or an agribusiness, means any federal or 
23State chartered bank, Federal Land Bank, Production Credit 
24Association, Bank for Cooperatives, federal or State chartered 
25savings and loan association or building and loan association, 
26Small Business Investment Company or any other institution 
 
 
10400SB0025ham004- 118 -LRB104 16098 AAS 29398 a

1qualified within this State to originate and service loans, 
2including, but without limitation to, insurance companies, 
3credit unions and mortgage loan companies. "Lender" also means 
4a wholly owned subsidiary of a manufacturer, seller or 
5distributor of goods or services that makes loans to 
6businesses or individuals, commonly known as a "captive 
7finance company".
8    (z) The term "agribusiness" means any sole proprietorship, 
9limited partnership, co-partnership, joint venture, 
10corporation or cooperative which operates or will operate a 
11facility located within the State or outside the State, 
12provided that, if any facility is located outside the State, 
13it must be owned, operated, leased, or managed by an entity 
14located within the State or an entity affiliated with an 
15entity located within the State, that is related to the 
16processing of agricultural commodities (including, without 
17limitation, the products of aquaculture, hydroponics and 
18silviculture) or the manufacturing, production or construction 
19of agricultural buildings, structures, equipment, implements, 
20and supplies, or any other facilities or processes used in 
21agricultural production. Agribusiness includes but is not 
22limited to the following:
23        (1) grain handling and processing, including grain 
24    storage, drying, treatment, conditioning, mailing and 
25    packaging;
26        (2) seed and feed grain development and processing;
 
 
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1        (3) fruit and vegetable processing, including 
2    preparation, canning and packaging;
3        (4) processing of livestock and livestock products, 
4    dairy products, poultry and poultry products, fish or 
5    apiarian products, including slaughter, shearing, 
6    collecting, preparation, canning and packaging;
7        (5) fertilizer and agricultural chemical 
8    manufacturing, processing, application and supplying;
9        (6) farm machinery, equipment and implement 
10    manufacturing and supplying;
11        (7) manufacturing and supplying of agricultural 
12    commodity processing machinery and equipment, including 
13    machinery and equipment used in slaughter, treatment, 
14    handling, collecting, preparation, canning or packaging of 
15    agricultural commodities;
16        (8) farm building and farm structure manufacturing, 
17    construction and supplying;
18        (9) construction, manufacturing, implementation, 
19    supplying or servicing of irrigation, drainage and soil 
20    and water conservation devices or equipment;
21        (10) fuel processing and development facilities that 
22    produce fuel from agricultural commodities or byproducts;
23        (11) facilities and equipment for processing and 
24    packaging agricultural commodities specifically for 
25    export;
26        (12) facilities and equipment for forestry product 
 
 
10400SB0025ham004- 120 -LRB104 16098 AAS 29398 a

1    processing and supplying, including sawmilling operations, 
2    wood chip operations, timber harvesting operations, and 
3    manufacturing of prefabricated buildings, paper, furniture 
4    or other goods from forestry products;
5        (13) facilities and equipment for research and 
6    development of products, processes and equipment for the 
7    production, processing, preparation or packaging of 
8    agricultural commodities and byproducts.
9    (aa) The term "asset" with respect to financing of any 
10agricultural facility or any agribusiness, means, but is not 
11limited to the following: cash crops or feed on hand; 
12livestock held for sale; breeding stock; marketable bonds and 
13securities; securities not readily marketable; accounts 
14receivable; notes receivable; cash invested in growing crops; 
15net cash value of life insurance; machinery and equipment; 
16cars and trucks; farm and other real estate including life 
17estates and personal residence; value of beneficial interests 
18in trusts; government payments or grants; and any other 
19assets.
20    (bb) The term "liability" with respect to financing of any 
21agricultural facility or any agribusiness shall include, but 
22not be limited to the following: accounts payable; notes or 
23other indebtedness owed to any source; taxes; rent; amounts 
24owed on real estate contracts or real estate mortgages; 
25judgments; accrued interest payable; and any other liability.
26    (cc) The term "Predecessor Authorities" means those 
 
 
10400SB0025ham004- 121 -LRB104 16098 AAS 29398 a

1authorities as described in Section 845-75.
2    (dd) The term "housing project" means a specific work or 
3improvement located within the State or outside the State and 
4undertaken to provide residential dwelling accommodations, 
5including the acquisition, construction or rehabilitation of 
6lands, buildings and community facilities and in connection 
7therewith to provide nonhousing facilities which are part of 
8the housing project, including land, buildings, improvements, 
9equipment and all ancillary facilities for use for offices, 
10stores, retirement homes, hotels, financial institutions, 
11service, health care, education, recreation or research 
12establishments, or any other commercial purpose which are or 
13are to be related to a housing development, provided that any 
14work or improvement located outside the State is owned, 
15operated, leased or managed by an entity located within the 
16State, or any entity affiliated with an entity located within 
17the State.
18    (ee) The term "conservation project" means any project 
19including the acquisition, construction, rehabilitation, 
20maintenance, operation, or upgrade that is intended to create 
21or expand open space or to reduce energy usage through 
22efficiency measures. For the purpose of this definition, "open 
23space" has the definition set forth under Section 10 of the 
24Illinois Open Land Trust Act. 
25    (ff) The term "significant presence" means the existence 
26within the State of the national or regional headquarters of 
 
 
10400SB0025ham004- 122 -LRB104 16098 AAS 29398 a

1an entity or group or such other facility of an entity or group 
2of entities where a significant amount of the business 
3functions are performed for such entity or group of entities. 
4    (gg) The term "municipal bond issuer" means the State or 
5any other state or commonwealth of the United States, or any 
6unit of local government, school district, agency or 
7instrumentality, office, department, division, bureau, 
8commission, college or university thereof located in the State 
9or any other state or commonwealth of the United States.
10    (hh) The term "municipal bond program project" means a 
11program for the funding of the purchase of bonds, notes or 
12other obligations issued by or on behalf of a municipal bond 
13issuer. 
14    (ii) The term "participating lender" means any trust 
15company, bank, savings bank, credit union, merchant bank, 
16investment bank, broker, investment trust, pension fund, 
17building and loan association, savings and loan association, 
18insurance company, venture capital company, or other 
19institution approved by the Authority which provides a portion 
20of the financing for a project.
21    (jj) The term "loan participation" means any loan in which 
22the Authority co-operates with a participating lender to 
23provide all or a portion of the financing for a project.
24    (kk) The term "PACE Project" means an energy project as 
25defined in Section 5 of the Property Assessed Clean Energy 
26Act. 
 
 
10400SB0025ham004- 123 -LRB104 16098 AAS 29398 a

1    (ll) The term "clean energy" means energy generation that 
2is substantially free (90% or more) of carbon dioxide 
3emissions by design or operations, or that otherwise 
4contributes to the reduction in emissions of environmentally 
5hazardous materials or reduces the volume of environmentally 
6dangerous materials.
7    (mm) The term "clean energy project" means the 
8acquisition, construction, refurbishment, creation, 
9development or redevelopment of any facility, equipment, 
10machinery, real property, or personal property for use by the 
11State or any unit of local government, school district, agency 
12or instrumentality, office, department, division, bureau, 
13commission, college, or university of the State, for use by 
14any person or institution, public or private, for profit or 
15not for profit, or for use in any trade or business, which the 
16Authority determines will aid, assist, or encourage the 
17development or implementation of clean energy in the State, or 
18as otherwise contemplated by Article 850.
19    (nn) The term "Climate Bank" means the Authority in the 
20exercise of those powers conferred on it by this Act related to 
21clean energy or clean water, drinking water, or wastewater 
22treatment.
23    (oo) "Equity investment eligible community" and "eligible 
24community" mean the geographic areas throughout Illinois that 
25would most benefit from equitable investments by the State 
26designed to combat discrimination. Specifically, the eligible 
 
 
10400SB0025ham004- 124 -LRB104 16098 AAS 29398 a

1communities shall be defined as the following areas:
2        (1) R3 Areas as established pursuant to Section 10-40 
3    of the Cannabis Regulation and Tax Act, where residents 
4    have historically been excluded from economic 
5    opportunities, including opportunities in the energy 
6    sector; and
7        (2) Environmental justice communities, as defined by 
8    the Illinois Power Agency pursuant to the Illinois Power 
9    Agency Act, where residents have historically been subject 
10    to disproportionate burdens of pollution, including 
11    pollution from the energy sector.
12    (pp) "Equity investment eligible person" and "eligible 
13person" mean the persons who would most benefit from equitable 
14investments by the State designed to combat discrimination. 
15Specifically, eligible persons 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    (qq) "Environmental justice community" means the 
22definition of that term based on existing methodologies and 
23findings used and as may be updated by the Illinois Power 
24Agency and its program administrator in the Illinois Solar for 
25All Program. 
26    (rr) "Energy storage project" means a project that uses 
 
 
10400SB0025ham004- 125 -LRB104 16098 AAS 29398 a

1technology for the storage of energy, including, without 
2limitation, the use of battery or electrochemical storage 
3technology for mobile or stationary applications.    
4(Source: P.A. 104-6, eff. 6-16-25.)
 
5    (20 ILCS 3501/850-20 new)
6    Sec. 850-20. Thermal Energy Network Revolving Loan and 
7Financial Assistance Program.
8    (a) As used in this Section:
9    "Program" means the Thermal Energy Network Revolving Loan 
10and Financial Assistance Program established under this 
11Section.    
12    "Thermal energy network" means all real estate, fixtures, 
13and personal property operated, owned, used, or to be used for 
14in connection with or to facilitate a community-scale 
15distribution infrastructure project that transfers heat into 
16and out of buildings using non-combusting thermal energy, 
17sourced from zero-emission technologies, including geothermal 
18energy, for the purpose of reducing emissions. "Thermal energy 
19network" includes, but is not limited to, real estate, 
20fixtures, and personal property that is operated, owned, or 
21used by multiple parties and community geothermal systems.    
22    (b) In its role as the Climate Bank for the State, the 
23Authority may, subject to available funding, establish and 
24administer a Thermal Energy Network Revolving Loan and 
25Financial Assistance Program. The Program shall provide access 
 
 
10400SB0025ham004- 126 -LRB104 16098 AAS 29398 a

1to capital for thermal energy network projects that take into 
2consideration the risks involved in the development of shared 
3heating and cooling systems and the required coordination 
4among multiple customers, as well as the benefits of enabling 
5low-cost decarbonization of residential, commercial, and 
6industrial buildings and processes. The Program may provide 
7loans, grants, or other financial assistance for thermal 
8energy network projects.
9    (c) The Authority may establish internal accounts 
10necessary to administer the Program, identify sources of 
11public and private funding and financial capital, and develop 
12any requirements or agreements necessary to successfully 
13execute the Program.
14    (d) The Authority shall coordinate and enter into any 
15necessary agreements with the Illinois Commerce Commission to 
16(i) develop and offer funding and financing to thermal energy 
17network pilot projects approved by the Commission under 
18subsection (a) of Section 8-513 of the Public Utilities Act, 
19(ii) receive funds as necessary and as approved by the 
20Commission under subsection (b) of Section 8-513 of the Public 
21Utilities Act, and (iii) establish any requirements necessary 
22to ensure compliance with the objectives of any federal 
23funding sources secured to support the Program.
24    (e) All repayments of loans or other financial assistance 
25made under the Program shall be used or leveraged to provide 
26additional capital to thermal energy network pilot projects 
 
 
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1that support the clean energy goals of the State, in 
2coordination with any rules established by the Illinois 
3Commerce Commission.
4    (f) The Authority may adopt any resolutions, plans, or 
5rules and fix, determine, charge, or collect any fees, 
6charges, costs, and expenses necessary to administer the 
7Program under this Section.
 
8    Section 90-12. The Illinois Power Agency Act is amended by 
9changing Sections 1-10, 1-20, 1-56, 1-75, and 1-125 as 
10follows:
 
11    (20 ILCS 3855/1-10)
12    Sec. 1-10. Definitions. 
13    "Agency" means the Illinois Power Agency.
14    "Agency loan agreement" means any agreement pursuant to 
15which the Illinois Finance Authority agrees to loan the 
16proceeds of revenue bonds issued with respect to a project to 
17the Agency upon terms providing for loan repayment 
18installments at least sufficient to pay when due all principal 
19of, interest and premium, if any, on those revenue bonds, and 
20providing for maintenance, insurance, and other matters in 
21respect of the project.
22    "Authority" means the Illinois Finance Authority.
23    "Brownfield site photovoltaic project" means photovoltaics 
24that are either:
 
 
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1        (1) interconnected to an electric utility as defined 
2    in this Section, a municipal utility as defined in this 
3    Section, a public utility as defined in Section 3-105 of 
4    the Public Utilities Act, or an electric cooperative as 
5    defined in Section 3-119 of the Public Utilities Act and 
6    located at a site that is regulated by any of the following 
7    entities under the following programs:
8            (A) the United States Environmental Protection 
9        Agency under the federal Comprehensive Environmental 
10        Response, Compensation, and Liability Act of 1980, as 
11        amended;
12            (B) the United States Environmental Protection 
13        Agency under the Corrective Action Program of the 
14        federal Resource Conservation and Recovery Act, as 
15        amended;
16            (C) the Illinois Environmental Protection Agency 
17        under the Illinois Site Remediation Program; or
18            (D) the Illinois Environmental Protection Agency 
19        under the Illinois Solid Waste Program; or 
20        (2) located at the site of a coal mine that has 
21    permanently ceased coal production, permanently halted any 
22    re-mining operations, and is no longer accepting any coal 
23    combustion residues; has both completed all clean-up and 
24    remediation obligations under the federal Surface Mining 
25    and Reclamation Act of 1977 and all applicable Illinois 
26    rules and any other clean-up, remediation, or ongoing 
 
 
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1    monitoring to safeguard the health and well-being of the 
2    people of the State of Illinois, as well as demonstrated 
3    compliance with all applicable federal and State 
4    environmental rules and regulations, including, but not 
5    limited, to 35 Ill. Adm. Code Part 845 and any rules for 
6    historic fill of coal combustion residuals, including any 
7    rules finalized in Subdocket A of Illinois Pollution 
8    Control Board docket R2020-019. 
9    "Clean coal facility" means an electric generating 
10facility that uses primarily coal as a feedstock and that 
11captures and sequesters carbon dioxide emissions at the 
12following levels: at least 50% of the total carbon dioxide 
13emissions that the facility would otherwise emit if, at the 
14time construction commences, the facility is scheduled to 
15commence operation before 2016, at least 70% of the total 
16carbon dioxide emissions that the facility would otherwise 
17emit if, at the time construction commences, the facility is 
18scheduled to commence operation during 2016 or 2017, and at 
19least 90% of the total carbon dioxide emissions that the 
20facility would otherwise emit if, at the time construction 
21commences, the facility is scheduled to commence operation 
22after 2017. The power block of the clean coal facility shall 
23not exceed allowable emission rates for sulfur dioxide, 
24nitrogen oxides, carbon monoxide, particulates and mercury for 
25a natural gas-fired combined-cycle facility the same size as 
26and in the same location as the clean coal facility at the time 
 
 
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1the clean coal facility obtains an approved air permit. All 
2coal used by a clean coal facility shall have high volatile 
3bituminous rank and greater than 1.7 pounds of sulfur per 
4million Btu content, unless the clean coal facility does not 
5use gasification technology and was operating as a 
6conventional coal-fired electric generating facility on June 
71, 2009 (the effective date of Public Act 95-1027). 
8    "Clean coal SNG brownfield facility" means a facility that 
9(1) has commenced construction by July 1, 2015 on an urban 
10brownfield site in a municipality with at least 1,000,000 
11residents; (2) uses a gasification process to produce 
12substitute natural gas; (3) uses coal as at least 50% of the 
13total feedstock over the term of any sourcing agreement with a 
14utility and the remainder of the feedstock may be either 
15petroleum coke or coal, with all such coal having a high 
16bituminous rank and greater than 1.7 pounds of sulfur per 
17million Btu content unless the facility reasonably determines 
18that it is necessary to use additional petroleum coke to 
19deliver additional consumer savings, in which case the 
20facility shall use coal for at least 35% of the total feedstock 
21over the term of any sourcing agreement; and (4) captures and 
22sequesters at least 85% of the total carbon dioxide emissions 
23that the facility would otherwise emit. 
24    "Clean coal SNG facility" means a facility that uses a 
25gasification process to produce substitute natural gas, that 
26sequesters at least 90% of the total carbon dioxide emissions 
 
 
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1that the facility would otherwise emit, that uses at least 90% 
2coal as a feedstock, with all such coal having a high 
3bituminous rank and greater than 1.7 pounds of sulfur per 
4million Btu content, and that has a valid and effective permit 
5to construct emission sources and air pollution control 
6equipment and approval with respect to the federal regulations 
7for Prevention of Significant Deterioration of Air Quality 
8(PSD) for the plant pursuant to the federal Clean Air Act; 
9provided, however, a clean coal SNG brownfield facility shall 
10not be a clean coal SNG facility. 
11    "Clean energy" means energy generation that is 90% or 
12greater free of carbon dioxide emissions. 
13    "Commission" means the Illinois Commerce Commission.
14    "Community renewable generation project" means an electric 
15generating facility that: 
16        (1) is powered by wind, solar thermal energy, 
17    photovoltaic cells or panels, biodiesel, crops and 
18    untreated and unadulterated organic waste biomass, and 
19    hydropower that does not involve new construction of dams; 
20        (2) is interconnected at the distribution system level 
21    of an electric utility as defined in this Section, a 
22    municipal utility as defined in this Section that owns or 
23    operates electric distribution facilities, a public 
24    utility as defined in Section 3-105 of the Public 
25    Utilities Act, or an electric cooperative, as defined in 
26    Section 3-119 of the Public Utilities Act;
 
 
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1        (3) credits the value of electricity generated by the 
2    facility to the subscribers of the facility; and
3        (4) is limited in nameplate capacity to less than or 
4    equal to 10,000 5,000 kilowatts.
5    "Costs incurred in connection with the development and 
6construction of a facility" means:
7        (1) the cost of acquisition of all real property, 
8    fixtures, and improvements in connection therewith and 
9    equipment, personal property, and other property, rights, 
10    and easements acquired that are deemed necessary for the 
11    operation and maintenance of the facility;
12        (2) financing costs with respect to bonds, notes, and 
13    other evidences of indebtedness of the Agency;
14        (3) all origination, commitment, utilization, 
15    facility, placement, underwriting, syndication, credit 
16    enhancement, and rating agency fees;
17        (4) engineering, design, procurement, consulting, 
18    legal, accounting, title insurance, survey, appraisal, 
19    escrow, trustee, collateral agency, interest rate hedging, 
20    interest rate swap, capitalized interest, contingency, as 
21    required by lenders, and other financing costs, and other 
22    expenses for professional services; and
23        (5) the costs of plans, specifications, site study and 
24    investigation, installation, surveys, other Agency costs 
25    and estimates of costs, and other expenses necessary or 
26    incidental to determining the feasibility of any project, 
 
 
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1    together with such other expenses as may be necessary or 
2    incidental to the financing, insuring, acquisition, and 
3    construction of a specific project and starting up, 
4    commissioning, and placing that project in operation. 
5    "Delivery services" has the same definition as found in 
6Section 16-102 of the Public Utilities Act. 
7    "Delivery year" means the consecutive 12-month period 
8beginning June 1 of a given year and ending May 31 of the 
9following year. 
10    "Department" means the Department of Commerce and Economic 
11Opportunity.
12    "Director" means the Director of the Illinois Power 
13Agency.
14    "Demand response Demand-response" means measures that 
15decrease peak electricity demand or shift demand from peak to 
16off-peak periods.
17    "Distributed renewable energy generation device" means a 
18device that is:
19        (1) powered by wind, solar thermal energy, 
20    photovoltaic cells or panels, biodiesel, crops and 
21    untreated and unadulterated organic waste biomass, tree 
22    waste, and hydropower that does not involve new 
23    construction of dams, waste heat to power systems, or 
24    qualified combined heat and power systems; 
25        (2) interconnected at the distribution system level of 
26    either an electric utility as defined in this Section, a 
 
 
10400SB0025ham004- 134 -LRB104 16098 AAS 29398 a

1    municipal utility as defined in this Section that owns or 
2    operates electric distribution facilities, or a rural 
3    electric cooperative as defined in Section 3-119 of the 
4    Public Utilities Act; 
5        (3) located on the customer side of the customer's 
6    electric meter and is primarily used to offset that 
7    customer's electricity load; and
8        (4) (blank). 
9    "Energy efficiency" means measures that reduce the amount 
10of electricity or natural gas consumed in order to achieve a 
11given end use. "Energy efficiency" includes voltage 
12optimization measures that optimize the voltage at points on 
13the electric distribution voltage system and thereby reduce 
14electricity consumption by electric customers' end use 
15devices. "Energy efficiency" also includes measures that 
16reduce the total Btus of electricity, natural gas, and other 
17fuels needed to meet the end use or uses. 
18    "Energy storage system" has the meaning given to that term 
19in Section 16-135 of the Public Utilities Act. "Energy storage 
20system" does not include technologies that require combustion.
21    "Energy storage resources" means the operational output or 
22capabilities of energy storage systems. "Energy storage 
23resources" includes, but is not limited to, energy, capacity, 
24and energy storage credits.    
25    "Electric utility" has the same definition as found in 
26Section 16-102 of the Public Utilities Act.
 
 
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1    "Equity investment eligible community" or "eligible 
2community" are synonymous and mean the geographic areas 
3throughout Illinois which would most benefit from equitable 
4investments by the State designed to combat discrimination. 
5Specifically, the eligible communities shall be defined as the 
6following areas:
7        (1) R3 Areas as established pursuant to Section 10-40 
8    of the Cannabis Regulation and Tax Act, where residents 
9    have historically been excluded from economic 
10    opportunities, including opportunities in the energy 
11    sector; and
12        (2) environmental justice communities, as defined by 
13    the Illinois Power Agency pursuant to the Illinois Power 
14    Agency Act, where residents have historically been subject 
15    to disproportionate burdens of pollution, including 
16    pollution from the energy sector.
17    "Equity eligible persons" or "eligible persons" means 
18persons who would most benefit from equitable investments by 
19the State designed to combat discrimination, specifically:
20        (1) persons who graduate from or are current or former 
21    participants in the Clean Jobs Workforce Network Program, 
22    the Clean Energy Contractor Incubator Program, the 
23    Illinois Climate Works Preapprenticeship Program, 
24    Returning Residents Clean Jobs Training Program, or the 
25    Clean Energy Primes Contractor Accelerator Program, and 
26    the solar training pipeline and multi-cultural jobs 
 
 
10400SB0025ham004- 136 -LRB104 16098 AAS 29398 a

1    program created in paragraphs (1) and (3) of subsection 
2    (a) (a)(1) and (a)(3) of Section 16-108.12 16-208.12 of 
3    the Public Utilities Act;
4        (2) persons who are graduates of or currently enrolled 
5    in the foster care system;
6        (3) persons who were formerly incarcerated;
7        (4) persons whose primary residence is in an equity 
8    investment eligible community.
9    "Equity eligible contractor" means a business that is 
10majority-owned by eligible persons, or a nonprofit or 
11cooperative that is majority-governed by eligible persons, or 
12is a natural person that is an eligible person offering 
13personal services as an independent contractor. 
14    "Facility" means an electric generating unit or a 
15co-generating unit that produces electricity along with 
16related equipment necessary to connect the facility to an 
17electric transmission or distribution system.
18    "General contractor" means the entity or organization with 
19main responsibility for the building of a construction project 
20and who is the party signing the prime construction contract 
21for the project. 
22    "Governmental aggregator" means one or more units of local 
23government that individually or collectively procure 
24electricity to serve residential retail electrical loads 
25located within its or their jurisdiction.
26    "High voltage direct current converter station" means the 
 
 
10400SB0025ham004- 137 -LRB104 16098 AAS 29398 a

1collection of equipment that converts direct current energy 
2from a high voltage direct current transmission line into 
3alternating current using Voltage Source Conversion technology 
4and that is interconnected with transmission or distribution 
5assets located in Illinois.
6    "High voltage direct current renewable energy credit" 
7means a renewable energy credit associated with a renewable 
8energy resource where the renewable energy resource has 
9entered into a contract to transmit the energy associated with 
10such renewable energy credit over high voltage direct current 
11transmission facilities. 
12    "High voltage direct current transmission facilities" 
13means the collection of installed equipment that converts 
14alternating current energy in one location to direct current 
15and transmits that direct current energy to a high voltage 
16direct current converter station using Voltage Source 
17Conversion technology. "High voltage direct current 
18transmission facilities" includes the high voltage direct 
19current converter station itself and associated high voltage 
20direct current transmission lines. Notwithstanding the 
21preceding, after September 15, 2021 (the effective date of 
22Public Act 102-662), an otherwise qualifying collection of 
23equipment does not qualify as high voltage direct current 
24transmission facilities unless (1) its developer entered into 
25a project labor agreement, is capable of transmitting 
26electricity at 525kv with an Illinois converter station 
 
 
10400SB0025ham004- 138 -LRB104 16098 AAS 29398 a

1located and interconnected in the region of the PJM 
2Interconnection, LLC, and the system does not operate as a 
3public utility, as that term is defined in Section 3-105 of the 
4Public Utilities Act, serving more than 100,000 customers as 
5of January 1, 2021; or (2) its developer has entered into a 
6project labor agreement prior to construction, the project is 
7capable of transmitting electricity at 525 kilovolts or above, 
8and the project has a converter station that is located in this 
9State or in a state adjacent to this State and is 
10interconnected to PJM Interconnection, LLC, the Midcontinent 
11Independent System Operator, Inc., or their successor.
12    "Hydropower" means any method of electricity generation or 
13storage that results from the flow of water, including 
14impoundment facilities, diversion facilities, and pumped 
15storage facilities. 
16    "Index price" means the real-time energy settlement price 
17at the applicable Illinois trading hub, such as PJM-NIHUB or 
18MISO-IL, for a given settlement period.
19    "Indexed renewable energy credit" means a tradable credit 
20that represents the environmental attributes of one megawatt 
21hour of energy produced from a renewable energy resource, the 
22price of which shall be calculated by subtracting the strike 
23price offered by a new utility-scale wind project or a new 
24utility-scale photovoltaic project from the index price in a 
25given settlement period. 
26    "Indexed renewable energy credit counterparty" has the 
 
 
10400SB0025ham004- 139 -LRB104 16098 AAS 29398 a

1same meaning as "public utility" as defined in Section 3-105 
2of the Public Utilities Act.
3    "Local government" means a unit of local government as 
4defined in Section 1 of Article VII of the Illinois 
5Constitution.
6    "Modernized" or "retooled" means the construction, repair, 
7maintenance, or significant expansion of turbines and existing 
8hydropower dams. 
9    "Municipality" means a city, village, or incorporated 
10town.
11    "Municipal utility" means a public utility owned and 
12operated by any subdivision or municipal corporation of this 
13State. 
14    "Nameplate capacity" means the aggregate inverter 
15nameplate capacity in kilowatts AC. 
16    "Person" means any natural person, firm, partnership, 
17corporation, either domestic or foreign, company, association, 
18limited liability company, joint stock company, or association 
19and includes any trustee, receiver, assignee, or personal 
20representative thereof.
21    "Project" means the planning, bidding, and construction of 
22a facility.
23    "Project labor agreement" means a pre-hire collective 
24bargaining agreement that covers all terms and conditions of 
25employment on a specific construction project and must include 
26the following:
 
 
10400SB0025ham004- 140 -LRB104 16098 AAS 29398 a

1        (1) provisions establishing the minimum hourly wage 
2    for each class of labor organization employee;
3        (2) provisions establishing the benefits and other 
4    compensation for each class of labor organization 
5    employee;
6        (3) provisions establishing that no strike or disputes 
7    will be engaged in by the labor organization employees;
8        (4) provisions establishing that no lockout or 
9    disputes will be engaged in by the general contractor 
10    building the project; and
11        (5) provisions for minorities and women, as defined 
12    under the Business Enterprise for Minorities, Women, and 
13    Persons with Disabilities Act, setting forth goals for 
14    apprenticeship hours to be performed by minorities and 
15    women and setting forth goals for total hours to be 
16    performed by underrepresented minorities and women.
17    A labor organization and the general contractor building 
18the project shall have the authority to include other terms 
19and conditions as they deem necessary. 
20    "Public utility" has the same definition as found in 
21Section 3-105 of the Public Utilities Act.
22    "Qualified combined heat and power systems" means systems 
23that, either simultaneously or sequentially, produce 
24electricity and useful thermal energy from a single fuel 
25source. Such systems are eligible for "renewable energy 
26credits" in an amount equal to its total energy output where a 
 
 
10400SB0025ham004- 141 -LRB104 16098 AAS 29398 a

1renewable fuel is consumed or in an amount equal to the net 
2reduction in nonrenewable fuel consumed on a total energy 
3output basis. 
4    "Real property" means any interest in land together with 
5all structures, fixtures, and improvements thereon, including 
6lands under water and riparian rights, any easements, 
7covenants, licenses, leases, rights-of-way, uses, and other 
8interests, together with any liens, judgments, mortgages, or 
9other claims or security interests related to real property.
10    "Renewable energy credit" means a tradable credit that 
11represents the environmental attributes of one megawatt hour 
12of energy produced from a renewable energy resource.
13    "Renewable energy resources" includes energy and its 
14associated renewable energy credit or renewable energy credits 
15from wind, solar thermal energy, photovoltaic cells and 
16panels, biodiesel, anaerobic digestion, crops and untreated 
17and unadulterated organic waste biomass, and hydropower that 
18does not involve new construction of dams, waste heat to power 
19systems, or qualified combined heat and power systems, or 
20geothermal heating and cooling systems that qualify for the 
21Geothermal Homes and Businesses Program. For purposes of this 
22Act, landfill gas produced in the State is considered a 
23renewable energy resource. "Renewable energy resources" does 
24not include the incineration or burning of tires, garbage, 
25general household, institutional, and commercial waste, 
26industrial lunchroom or office waste, landscape waste, 
 
 
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1railroad crossties, utility poles, or construction or 
2demolition debris, other than untreated and unadulterated 
3waste wood. "Renewable energy resources" also includes high 
4voltage direct current renewable energy credits and the 
5associated energy converted to alternating current by a high 
6voltage direct current converter station to the extent that: 
7(1) the generator of such renewable energy resource contracted 
8with a third party to transmit the energy over the high voltage 
9direct current transmission facilities, and (2) the 
10third-party contracting for delivery of renewable energy 
11resources over the high voltage direct current transmission 
12facilities have ownership rights over the unretired associated 
13high voltage direct current renewable energy credit. 
14    "Retail customer" has the same definition as found in 
15Section 16-102 of the Public Utilities Act. 
16    "Revenue bond" means any bond, note, or other evidence of 
17indebtedness issued by the Authority, the principal and 
18interest of which is payable solely from revenues or income 
19derived from any project or activity of the Agency.
20    "Sequester" means permanent storage of carbon dioxide by 
21injecting it into a saline aquifer, a depleted gas reservoir, 
22or an oil reservoir, directly or through an enhanced oil 
23recovery process that may involve intermediate storage, 
24regardless of whether these activities are conducted by a 
25clean coal facility, a clean coal SNG facility, a clean coal 
26SNG brownfield facility, or a party with which a clean coal 
 
 
10400SB0025ham004- 143 -LRB104 16098 AAS 29398 a

1facility, clean coal SNG facility, or clean coal SNG 
2brownfield facility has contracted for such purposes. 
3    "Service area" has the same definition as found in Section 
416-102 of the Public Utilities Act. 
5    "Settlement period" means the period of time utilized by 
6MISO and PJM and their successor organizations as the basis 
7for settlement calculations in the real-time energy market. 
8    "Sourcing agreement" means (i) in the case of an electric 
9utility, an agreement between the owner of a clean coal 
10facility and such electric utility, which agreement shall have 
11terms and conditions meeting the requirements of paragraph (3) 
12of subsection (d) of Section 1-75, (ii) in the case of an 
13alternative retail electric supplier, an agreement between the 
14owner of a clean coal facility and such alternative retail 
15electric supplier, which agreement shall have terms and 
16conditions meeting the requirements of Section 16-115(d)(5) of 
17the Public Utilities Act, and (iii) in case of a gas utility, 
18an agreement between the owner of a clean coal SNG brownfield 
19facility and the gas utility, which agreement shall have the 
20terms and conditions meeting the requirements of subsection 
21(h-1) of Section 9-220 of the Public Utilities Act. 
22    "Strike price" means a contract price for energy and 
23renewable energy credits from a new utility-scale wind project 
24or a new utility-scale photovoltaic project. 
25    "Subscriber" means a person who (i) takes delivery service 
26from an electric utility, and (ii) has a subscription of no 
 
 
10400SB0025ham004- 144 -LRB104 16098 AAS 29398 a

1less than 200 watts to a community renewable generation 
2project that is located in the electric utility's service 
3area. No subscriber's subscriptions may total more than 40% of 
4the nameplate capacity of an individual community renewable 
5generation project. Entities that are affiliated by virtue of 
6a common parent shall not represent multiple subscriptions 
7that total more than 40% of the nameplate capacity of an 
8individual community renewable generation project.
9    "Subscription" means an interest in a community renewable 
10generation project expressed in kilowatts, which is sized 
11primarily to offset part or all of the subscriber's 
12electricity usage. 
13    "Substitute natural gas" or "SNG" means a gas manufactured 
14by gasification of hydrocarbon feedstock, which is 
15substantially interchangeable in use and distribution with 
16conventional natural gas. 
17    "Total resource cost test" or "TRC test" means a standard 
18that is met if, for an investment in energy efficiency or 
19demand-response measures, the benefit-cost ratio is greater 
20than one. The benefit-cost ratio is the ratio of the net 
21present value of the total benefits of the program to the net 
22present value of the total costs as calculated over the 
23lifetime of the measures. A total resource cost test compares 
24the sum of avoided electric utility costs, representing the 
25benefits that accrue to the system and the participant in the 
26delivery of those efficiency measures and including avoided 
 
 
10400SB0025ham004- 145 -LRB104 16098 AAS 29398 a

1costs associated with reduced use of natural gas or other 
2fuels, avoided costs associated with reduced water 
3consumption, and avoided costs associated with reduced 
4operation and maintenance costs, and avoided societal costs 
5associated with reductions in greenhouse gas emissions, as 
6well as other quantifiable societal benefits, to the sum of 
7all incremental costs of end-use measures that are implemented 
8due to the program (including both utility and participant 
9contributions), plus costs to administer, deliver, and 
10evaluate each demand-side program, to quantify the net savings 
11obtained by substituting the demand-side program for supply 
12resources. The societal costs associated with greenhouse gas 
13emissions shall be $200 per short ton, expressed in 2025 
14dollars or the most recently approved estimate developed by 
15the federal government using a real discount rate consistent 
16with long-term Treasury bond yields, whichever is greater. 
17Changes in greenhouse gas emissions due to changes in 
18electricity consumption shall be estimated using long-run 
19marginal emissions rates developed by the National Renewable 
20Energy Laboratory's Cambium model or other Illinois-specific 
21modeling of comparable analytical rigor. In calculating 
22avoided costs of power and energy that an electric utility 
23would otherwise have had to acquire, reasonable estimates 
24shall be included of financial costs likely to be imposed by 
25future regulations and legislation on emissions of greenhouse 
26gases. In discounting future societal costs and benefits for 
 
 
10400SB0025ham004- 146 -LRB104 16098 AAS 29398 a

1the purpose of calculating net present values, a societal 
2discount rate based on actual, long-term Treasury bond yields 
3should be used. Notwithstanding anything to the contrary, the 
4TRC test shall not include or take into account a calculation 
5of market price suppression effects or demand reduction 
6induced price effects. 
7    "Utility-scale solar project" means an electric generating 
8facility that:
9        (1) generates electricity using photovoltaic cells; 
10    and
11        (2) has a nameplate capacity that is greater than 
12    5,000 kilowatts alternating current (AC). 
13    "Utility-scale wind project" means an electric generating 
14facility that:
15        (1) generates electricity using wind; and
16        (2) has a nameplate capacity that is greater than 
17    5,000 kilowatts. 
18    "Waste Heat to Power Systems" means systems that capture 
19and generate electricity from energy that would otherwise be 
20lost to the atmosphere without the use of additional fuel. 
21    "Zero emission credit" means a tradable credit that 
22represents the environmental attributes of one megawatt hour 
23of energy produced from a zero emission facility.
24    "Zero emission facility" means a facility that: (1) is 
25fueled by nuclear power; and (2) is interconnected with PJM 
26Interconnection, LLC or the Midcontinent Independent System 
 
 
10400SB0025ham004- 147 -LRB104 16098 AAS 29398 a

1Operator, Inc., or their successors.
2(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23; 
3103-380, eff. 1-1-24.)
 
4    (20 ILCS 3855/1-20)
5    Sec. 1-20. General powers and duties of the Agency. 
6    (a) The Agency is authorized to do each of the following:
7        (1) Develop electricity procurement plans to ensure 
8    adequate, reliable, affordable, efficient, and 
9    environmentally sustainable electric service at the lowest 
10    total cost over time, taking into account any benefits of 
11    price stability, for electric utilities that on December 
12    31, 2005 provided electric service to at least 100,000 
13    customers in Illinois and for small multi-jurisdictional 
14    electric utilities that (A) on December 31, 2005 served 
15    less than 100,000 customers in Illinois and (B) request a 
16    procurement plan for their Illinois jurisdictional load. 
17    Except as provided in paragraph (1.5) of this subsection 
18    (a), the electricity procurement plans shall be updated on 
19    an annual basis and shall include electricity generated 
20    from renewable resources sufficient to achieve the 
21    standards specified in this Act. Beginning with the 
22    delivery year commencing June 1, 2017, develop procurement 
23    plans to include zero emission credits generated from zero 
24    emission facilities sufficient to achieve the standards 
25    specified in this Act. Beginning with the delivery year 
 
 
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1    commencing on June 1, 2022, the Agency is authorized to 
2    develop carbon mitigation credit procurement plans to 
3    include carbon mitigation credits generated from 
4    carbon-free energy resources sufficient to achieve the 
5    standards specified in this Act. 
6        (1.5) Develop a long-term renewable resources 
7    procurement plan in accordance with subsection (c) of 
8    Section 1-75 of this Act for renewable energy credits in 
9    amounts sufficient to achieve the standards specified in 
10    this Act for delivery years commencing June 1, 2017 and 
11    for the programs and renewable energy credits specified in 
12    Section 1-56 of this Act. Electricity procurement plans 
13    for delivery years commencing after May 31, 2017, shall 
14    not include procurement of renewable energy resources. 
15        (2) Conduct competitive procurement processes to 
16    procure the supply resources identified in the electricity 
17    procurement plan, pursuant to Section 16-111.5 of the 
18    Public Utilities Act, and, for the delivery year 
19    commencing June 1, 2017, conduct procurement processes to 
20    procure zero emission credits from zero emission 
21    facilities, under subsection (d-5) of Section 1-75 of this 
22    Act. For the delivery year commencing June 1, 2022, the 
23    Agency is authorized to conduct procurement processes to 
24    procure carbon mitigation credits from carbon-free energy 
25    resources, under subsection (d-10) of Section 1-75 of this 
26    Act. 
 
 
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1        (2.5) Beginning with the procurement for the 2017 
2    delivery year, conduct competitive procurement processes 
3    and implement programs to procure renewable energy credits 
4    identified in the long-term renewable resources 
5    procurement plan developed and approved under subsection 
6    (c) of Section 1-75 of this Act and Section 16-111.5 of the 
7    Public Utilities Act. 
8        (2.10) Oversee the procurement by electric utilities 
9    that served more than 300,000 customers in this State as 
10    of January 1, 2019 of renewable energy credits from new 
11    renewable energy facilities to be installed, along with 
12    energy storage facilities, at or adjacent to the sites of 
13    electric generating facilities that burned coal as their 
14    primary fuel source as of January 1, 2016 in accordance 
15    with subsection (c-5) of Section 1-75 of this Act.
16        (2.15) Oversee the procurement by electric utilities 
17    of renewable energy credits from newly modernized or 
18    retooled hydropower dams or dams that have been converted 
19    to support hydropower generation. 
20        (3) Develop electric generation and co-generation 
21    facilities that use indigenous coal or renewable 
22    resources, or both, financed with bonds issued by the 
23    Illinois Finance Authority.
24        (4) Supply electricity from the Agency's facilities at 
25    cost to one or more of the following: municipal electric 
26    systems, governmental aggregators, or rural electric 
 
 
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1    cooperatives in Illinois.
2        (5) Develop a long-term energy storage resources 
3    procurement plan and conduct competitive procurement 
4    processes in accordance with subsection (d-20) of Section 
5    1-75.    
6    (b) Except as otherwise limited by this Act, the Agency 
7has all of the powers necessary or convenient to carry out the 
8purposes and provisions of this Act, including without 
9limitation, each of the following:
10        (1) To have a corporate seal, and to alter that seal at 
11    pleasure, and to use it by causing it or a facsimile to be 
12    affixed or impressed or reproduced in any other manner.
13        (2) To use the services of the Illinois Finance 
14    Authority necessary to carry out the Agency's purposes.
15        (3) To negotiate and enter into loan agreements and 
16    other agreements with the Illinois Finance Authority.
17        (4) To obtain and employ personnel and hire 
18    consultants that are necessary to fulfill the Agency's 
19    purposes, and to make expenditures for that purpose within 
20    the appropriations for that purpose.
21        (5) To purchase, receive, take by grant, gift, devise, 
22    bequest, or otherwise, lease, or otherwise acquire, own, 
23    hold, improve, employ, use, and otherwise deal in and 
24    with, real or personal property whether tangible or 
25    intangible, or any interest therein, within the State.
26        (6) To acquire real or personal property, whether 
 
 
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1    tangible or intangible, including without limitation 
2    property rights, interests in property, franchises, 
3    obligations, contracts, and debt and equity securities, 
4    and to do so by the exercise of the power of eminent domain 
5    in accordance with Section 1-21; except that any real 
6    property acquired by the exercise of the power of eminent 
7    domain must be located within the State.
8        (7) To sell, convey, lease, exchange, transfer, 
9    abandon, or otherwise dispose of, or mortgage, pledge, or 
10    create a security interest in, any of its assets, 
11    properties, or any interest therein, wherever situated.
12        (8) To purchase, take, receive, subscribe for, or 
13    otherwise acquire, hold, make a tender offer for, vote, 
14    employ, sell, lend, lease, exchange, transfer, or 
15    otherwise dispose of, mortgage, pledge, or grant a 
16    security interest in, use, and otherwise deal in and with, 
17    bonds and other obligations, shares, or other securities 
18    (or interests therein) issued by others, whether engaged 
19    in a similar or different business or activity.
20        (9) To make and execute agreements, contracts, and 
21    other instruments necessary or convenient in the exercise 
22    of the powers and functions of the Agency under this Act, 
23    including contracts with any person, including personal 
24    service contracts, or with any local government, State 
25    agency, or other entity; and all State agencies and all 
26    local governments are authorized to enter into and do all 
 
 
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1    things necessary to perform any such agreement, contract, 
2    or other instrument with the Agency. No such agreement, 
3    contract, or other instrument shall exceed 40 years.
4        (10) To lend money, invest and reinvest its funds in 
5    accordance with the Public Funds Investment Act, and take 
6    and hold real and personal property as security for the 
7    payment of funds loaned or invested.
8        (11) To borrow money at such rate or rates of interest 
9    as the Agency may determine, issue its notes, bonds, or 
10    other obligations to evidence that indebtedness, and 
11    secure any of its obligations by mortgage or pledge of its 
12    real or personal property, machinery, equipment, 
13    structures, fixtures, inventories, revenues, grants, and 
14    other funds as provided or any interest therein, wherever 
15    situated.
16        (12) To enter into agreements with the Illinois 
17    Finance Authority to issue bonds whether or not the income 
18    therefrom is exempt from federal taxation.
19        (13) To procure insurance against any loss in 
20    connection with its properties or operations in such 
21    amount or amounts and from such insurers, including the 
22    federal government, as it may deem necessary or desirable, 
23    and to pay any premiums therefor.
24        (14) To negotiate and enter into agreements with 
25    trustees or receivers appointed by United States 
26    bankruptcy courts or federal district courts or in other 
 
 
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1    proceedings involving adjustment of debts and authorize 
2    proceedings involving adjustment of debts and authorize 
3    legal counsel for the Agency to appear in any such 
4    proceedings.
5        (15) To file a petition under Chapter 9 of Title 11 of 
6    the United States Bankruptcy Code or take other similar 
7    action for the adjustment of its debts.
8        (16) To enter into management agreements for the 
9    operation of any of the property or facilities owned by 
10    the Agency.
11        (17) To enter into an agreement to transfer and to 
12    transfer any land, facilities, fixtures, or equipment of 
13    the Agency to one or more municipal electric systems, 
14    governmental aggregators, or rural electric agencies or 
15    cooperatives, for such consideration and upon such terms 
16    as the Agency may determine to be in the best interest of 
17    the residents of Illinois.
18        (18) To enter upon any lands and within any building 
19    whenever in its judgment it may be necessary for the 
20    purpose of making surveys and examinations to accomplish 
21    any purpose authorized by this Act.
22        (19) To maintain an office or offices at such place or 
23    places in the State as it may determine.
24        (20) To request information, and to make any inquiry, 
25    investigation, survey, or study that the Agency may deem 
26    necessary to enable it effectively to carry out the 
 
 
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1    provisions of this Act.
2        (21) To accept and expend appropriations.
3        (22) To engage in any activity or operation that is 
4    incidental to and in furtherance of efficient operation to 
5    accomplish the Agency's purposes, including hiring 
6    employees that the Director deems essential for the 
7    operations of the Agency.
8        (23) To adopt, revise, amend, and repeal rules with 
9    respect to its operations, properties, and facilities as 
10    may be necessary or convenient to carry out the purposes 
11    of this Act, subject to the provisions of the Illinois 
12    Administrative Procedure Act and Sections 1-22 and 1-35 of 
13    this Act.
14        (24) To establish and collect charges and fees as 
15    described in this Act.
16        (25) To conduct competitive gasification feedstock 
17    procurement processes to procure the feedstocks for the 
18    clean coal SNG brownfield facility in accordance with the 
19    requirements of Section 1-78 of this Act. 
20        (26) To review, revise, and approve sourcing 
21    agreements and mediate and resolve disputes between gas 
22    utilities and the clean coal SNG brownfield facility 
23    pursuant to subsection (h-1) of Section 9-220 of the 
24    Public Utilities Act. 
25        (27) To request, review and accept proposals, execute 
26    contracts, purchase renewable energy credits and otherwise 
 
 
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1    dedicate funds from the Illinois Power Agency Renewable 
2    Energy Resources Fund to create and carry out the 
3    objectives of the Illinois Solar for All Program in 
4    accordance with Section 1-56 of this Act. 
5        (28) To ensure Illinois residents and business benefit 
6    from programs administered by the Agency and are properly 
7    protected from any deceptive or misleading marketing 
8    practices by participants in the Agency's programs and 
9    procurements. 
10    (c) In conducting the procurement of electricity or other 
11products, beginning January 1, 2022, the Agency shall not 
12procure any products or services from persons or organizations 
13that are in violation of the Displaced Energy Workers Bill of 
14Rights, as provided under the Energy Community Reinvestment 
15Act at the time of the procurement event or fail to comply the 
16labor standards established in subparagraph (Q) of paragraph 
17(1) of subsection (c) of Section 1-75. 
18(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
19    (20 ILCS 3855/1-56)
20    Sec. 1-56. Illinois Power Agency Renewable Energy 
21Resources Fund; Illinois Solar for All Program.
22    (a) The Illinois Power Agency Renewable Energy Resources 
23Fund is created as a special fund in the State treasury.
24    (b) The Illinois Power Agency Renewable Energy Resources 
25Fund shall be administered by the Agency as described in this 
 
 
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1subsection (b), provided that the changes to this subsection 
2(b) made by Public Act 99-906 shall not interfere with 
3existing contracts under this Section. 
4        (1) The Illinois Power Agency Renewable Energy 
5    Resources Fund shall be used to purchase renewable energy 
6    credits according to any approved procurement plan 
7    developed by the Agency prior to June 1, 2017.
8        (2) The Illinois Power Agency Renewable Energy 
9    Resources Fund shall also be used to create the Illinois 
10    Solar for All Program, which provides incentives for 
11    low-income distributed generation and community solar 
12    projects, and other associated approved expenditures. The 
13    objectives of the Illinois Solar for All Program are to 
14    bring photovoltaics to low-income communities in this 
15    State in a manner that maximizes the development of new 
16    photovoltaic generating facilities, to create a long-term, 
17    low-income solar marketplace throughout this State, to 
18    integrate, through interaction with stakeholders, with 
19    existing energy efficiency initiatives, and to minimize 
20    administrative costs. The Illinois Solar for All Program 
21    shall be implemented in a manner that seeks to minimize 
22    administrative costs, and maximize efficiencies and 
23    synergies available through coordination with similar 
24    initiatives, including the Adjustable Block program 
25    described in subparagraphs (K) through (M) of paragraph 
26    (1) of subsection (c) of Section 1-75, energy efficiency 
 
 
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1    programs, job training programs, and community action 
2    agencies, and agencies that administer the Low-Income Home 
3    Energy Assistance Program. The Agency shall strive to 
4    ensure that renewable energy credits procured through the 
5    Illinois Solar for All Program and each of its subprograms 
6    are purchased from projects across the breadth of 
7    low-income and environmental justice communities in 
8    Illinois, including both urban and rural communities, are 
9    not concentrated in a few communities, and do not exclude 
10    particular low-income or environmental justice 
11    communities. The Agency shall include a description of its 
12    proposed approach to the design, administration, 
13    implementation and evaluation of the Illinois Solar for 
14    All Program, as part of the long-term renewable resources 
15    procurement plan authorized by subsection (c) of Section 
16    1-75 of this Act, and the program shall be designed to grow 
17    the low-income solar market. The Agency or utility, as 
18    applicable, shall purchase renewable energy credits from 
19    the (i) photovoltaic distributed renewable energy 
20    generation projects and (ii) community solar projects that 
21    are procured under procurement processes authorized by the 
22    long-term renewable resources procurement plans approved 
23    by the Commission.
24        The Illinois Solar for All Program shall include the 
25    program offerings described in subparagraphs (A) through 
26    (E) of this paragraph (2), which the Agency shall 
 
 
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1    implement through contracts with third-party providers 
2    and, subject to appropriation, pay the approximate amounts 
3    identified using monies available in the Illinois Power 
4    Agency Renewable Energy Resources Fund. Each contract that 
5    provides for the installation of solar facilities shall 
6    provide that the solar facilities will produce energy and 
7    economic benefits, at a level determined by the Agency to 
8    be reasonable, for the participating low-income customers. 
9    The monies available in the Illinois Power Agency 
10    Renewable Energy Resources Fund and not otherwise 
11    committed to contracts executed under subsection (i) of 
12    this Section, as well as, in the case of the programs 
13    described under subparagraphs (A) through (E) of this 
14    paragraph (2), funding authorized pursuant to subparagraph 
15    (O) of paragraph (1) of subsection (c) of Section 1-75 of 
16    this Act, shall initially be allocated among the programs 
17    described in this paragraph (2), as follows: 35% of these 
18    funds shall be allocated to programs described in 
19    subparagraphs (A) and (E) of this paragraph (2), 40% of 
20    these funds shall be allocated to programs described in 
21    subparagraph (B) of this paragraph (2), and 25% of these 
22    funds shall be allocated to programs described in 
23    subparagraph (C) of this paragraph (2). The allocation of 
24    funds among subparagraphs (A), (B), (C), and (E) of this 
25    paragraph (2) may be changed if the Agency, after 
26    receiving input through a stakeholder process, determines 
 
 
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1    incentives in subparagraph subparagraphs (A), (B), (C), or 
2    (E) of this paragraph (2) have not been adequately 
3    subscribed to fully utilize available Illinois Solar for 
4    All Program funds.
5        Contracts that will be paid with funds in the Illinois 
6    Power Agency Renewable Energy Resources Fund shall be 
7    executed by the Agency. Contracts that will be paid with 
8    funds collected by an electric utility shall be executed 
9    by the electric utility.
10        Contracts under the Illinois Solar for All Program 
11    shall include an approach, as set forth in the long-term 
12    renewable resources procurement plans, to ensure the 
13    wholesale market value of the energy is credited to 
14    participating low-income customers or organizations and to 
15    ensure tangible economic benefits flow directly to program 
16    participants, except in the case of low-income 
17    multi-family housing where the low-income customer does 
18    not directly pay for energy. Priority shall be given to 
19    projects that demonstrate meaningful involvement of 
20    low-income community members in designing the initial 
21    proposals. Acceptable proposals to implement projects must 
22    demonstrate the applicant's ability to conduct initial 
23    community outreach, education, and recruitment of 
24    low-income participants in the community. Projects 
25    submitted by approved vendors must either comply with the 
26    minimum equity standard set forth in subsection (c-10) of 
 
 
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1    Section 1-75 of this Act or must include job training 
2    opportunities if available, with the specific level of 
3    trainee usage to be determined through the Agency's 
4    long-term renewable resources procurement plan, and the 
5    Illinois Solar for All Program Administrator shall 
6    coordinate with the job training programs described in 
7    paragraph (1) of subsection (a) of Section 16-108.12 of 
8    the Public Utilities Act and in the Energy Transition Act. 
9        The Agency shall make every effort to ensure that 
10    small and emerging businesses, particularly those located 
11    in low-income and environmental justice communities, are 
12    able to participate in the Illinois Solar for All Program. 
13    These efforts may include, but shall not be limited to, 
14    proactive support from the program administrator, 
15    different or preferred access to subprograms and 
16    administrator-identified customers or grassroots 
17    education provider-identified customers, and different 
18    incentive levels. The Agency shall report on progress and 
19    barriers to participation of small and emerging businesses 
20    in the Illinois Solar for All Program at least once a year. 
21    The report shall be made available on the Agency's website 
22    and, in years when the Agency is updating its long-term 
23    renewable resources procurement plan, included in that 
24    Plan. 
25            (A) Low-income single-family and small multifamily 
26        solar incentive. This program will provide incentives 
 
 
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1        to low-income customers, either directly or through 
2        solar providers, to increase the participation of 
3        low-income households in photovoltaic on-site 
4        distributed generation at residential buildings 
5        containing one to 4 units. Companies participating in 
6        this program that install solar panels shall commit to 
7        meeting a minimum equity standard or hiring job 
8        trainees for a portion of their low-income 
9        installations, and an administrator shall facilitate 
10        partnering the companies that install solar panels 
11        with entities that provide solar panel installation 
12        job training. It is a goal of this program that a 
13        minimum of 25% of the incentives for this program be 
14        allocated to projects located within environmental 
15        justice communities. Contracts entered into under this 
16        paragraph may be entered into with an entity that will 
17        develop and administer the program and shall also 
18        include contracts for renewable energy credits from 
19        the photovoltaic distributed generation that is the 
20        subject of the program, as set forth in the long-term 
21        renewable resources procurement plan. Additionally:
22                (i) The Agency shall reserve a portion of this 
23            program for projects that promote energy 
24            sovereignty through ownership of projects by 
25            low-income households, not-for-profit 
26            organizations providing services to low-income 
 
 
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1            households, affordable housing owners, community 
2            cooperatives, or community-based limited liability 
3            companies providing services to low-income 
4            households. Projects that feature energy ownership 
5            should ensure that local people have control of 
6            the project and reap benefits from the project 
7            over and above energy bill savings. The Agency may 
8            consider the inclusion of projects that promote 
9            ownership over time or that involve partial 
10            project ownership by communities, as promoting 
11            energy sovereignty. Incentives for projects that 
12            promote energy sovereignty may be higher than 
13            incentives for equivalent projects that do not 
14            promote energy sovereignty under this same 
15            program.
16                (ii) Through its long-term renewable resources 
17            procurement plan, the Agency shall consider 
18            additional program and contract requirements to 
19            ensure faithful compliance by applicants 
20            benefiting from preferences for projects 
21            designated to promote energy sovereignty. The 
22            Agency shall make every effort to enable solar 
23            providers already participating in the Adjustable 
24            Block program Program under subparagraph (K) of 
25            paragraph (1) of subsection (c) of Section 1-75 of 
26            this Act, and particularly solar providers 
 
 
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1            developing projects under item (i) of subparagraph 
2            (K) of paragraph (1) of subsection (c) of Section 
3            1-75 of this Act to easily participate in the 
4            Low-Income Distributed Generation Incentive 
5            program described under this subparagraph (A), and 
6            vice versa. This effort may include, but shall not 
7            be limited to, utilizing similar or the same 
8            application systems and processes, utilizing    
9            similar or the same forms and formats of 
10            communication, and providing active outreach to 
11            companies participating in one program but not the 
12            other. The Agency shall report on efforts made to 
13            encourage this cross-participation in its 
14            long-term renewable resources procurement plan. 
15                (iii) To maximize equitable participation in 
16            this program and overcome challenges facing the 
17            development of residential solar projects, the 
18            Agency may propose a payment structure for 
19            contracts executed pursuant to this subparagraph 
20            (A) under which applicant firms are advanced 
21            capital that is disbursed after contract execution 
22            but before the contracted project's energization, 
23            upon a demonstration of qualification or need 
24            under criteria established by the Agency that are 
25            focused on supporting the small and emerging 
26            businesses and the businesses that most acutely 
 
 
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1            face barriers to capital access, which severely 
2            limits the businesses' participation in the 
3            program described in this subparagraph (A). The 
4            amount or percentage of capital advanced before 
5            project energization shall be designed to overcome 
6            the barriers in access to capital that are faced 
7            by an applicant. The amount or percentage of 
8            advanced capital may vary under this subparagraph 
9            (A) by an applicant's demonstration of need, with 
10            such levels to be established through the 
11            Long-Term Renewable Resources Procurement Plan and 
12            any application requirements or evaluation 
13            criteria developed under that Plan.    
14            (B) Low-Income Community Solar Project Initiative. 
15        Incentives shall be offered to low-income customers, 
16        either directly or through developers, to increase the 
17        participation of low-income subscribers of community 
18        solar projects. The developer of each project shall 
19        identify its partnership with community stakeholders 
20        regarding the location, development, and participation 
21        in the project, provided that nothing shall preclude a 
22        project from including an anchor tenant that does not 
23        qualify as low-income. Companies participating in this 
24        program that develop or install solar projects shall 
25        commit to meeting a minimum equity standard or to    
26        hiring job trainees for a portion of their low-income 
 
 
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1        installations, and an administrator shall facilitate 
2        partnering the companies that install solar projects 
3        with entities that provide solar installation and 
4        related job training. It is a goal of this program that 
5        a minimum of 25% of the incentives for this program be 
6        allocated to community photovoltaic projects in 
7        environmental justice communities. The Agency shall 
8        reserve a portion of this program for projects that 
9        promote energy sovereignty through ownership of 
10        projects by low-income households, not-for-profit 
11        organizations providing services to low-income 
12        households, affordable housing owners, or 
13        community-based limited liability companies providing 
14        services to low-income households. Projects that 
15        feature energy ownership should ensure that local 
16        people have control of the project and reap benefits 
17        from the project over and above energy bill savings. 
18        The Agency may consider the inclusion of projects that 
19        promote ownership over time or that involve partial 
20        project ownership by communities, as promoting energy 
21        sovereignty. Incentives for projects that promote 
22        energy sovereignty may be higher than incentives for 
23        equivalent projects that do not promote energy 
24        sovereignty under this same program. Contracts entered 
25        into under this paragraph may be entered into with 
26        developers and shall also include contracts for 
 
 
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1        renewable energy credits related to the program.
2            (C) Incentives for non-profits and public 
3        facilities. Under this program funds shall be used to 
4        support on-site photovoltaic distributed renewable 
5        energy generation devices to serve the load associated 
6        with not-for-profit customers and to support 
7        photovoltaic distributed renewable energy generation 
8        that uses photovoltaic technology to serve the load 
9        associated with public sector customers taking service 
10        at public buildings. Master-metered multifamily 
11        buildings that primarily house income-eligible 
12        residents may qualify under this subparagraph (C). 
13        Nonprofits and public facilities that can demonstrate 
14        that the nonprofit or public facility serves 
15        income-qualified or environmental justice communities 
16        may potentially qualify for the program, regardless of 
17        physical location. Qualification may be determined 
18        using the same procedures applied to critical service 
19        provider requests for the purpose of establishing 
20        project eligibility in areas that are not designated 
21        as income-eligible or environmental justice 
22        communities. Companies participating in this program 
23        that develop or install solar projects shall commit to 
24        meeting a minimum equity standard or to hiring job 
25        trainees for a portion of their low-income 
26        installations, and an administrator shall facilitate 
 
 
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1        partnering the companies that install solar projects 
2        with entities that provide solar installation and 
3        related job training. Through its long-term renewable 
4        resources procurement plan, the Agency shall consider 
5        additional program and contract requirements to ensure 
6        faithful compliance by applicants benefiting from 
7        preferences for projects designated to promote energy 
8        sovereignty. It is a goal of this program that at least 
9        25% of the incentives for this program be allocated to 
10        projects located in environmental justice communities. 
11        Contracts entered into under this paragraph may be 
12        entered into with an entity that will develop and 
13        administer the program or with developers and shall 
14        also include contracts for renewable energy credits 
15        related to the program.
16            (D) (Blank). 
17            (E) Low-income large multifamily solar incentive. 
18        This program shall provide incentives to low-income 
19        customers, either directly or through solar providers, 
20        to increase the participation of low-income households 
21        in photovoltaic on-site distributed generation at 
22        residential buildings with 5 or more units. Companies 
23        participating in this program that develop or install 
24        solar projects shall commit to meeting a minimum 
25        equity standard or to hiring job trainees for a 
26        portion of their low-income installations, and an 
 
 
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1        administrator shall facilitate partnering the 
2        companies that install solar projects with entities 
3        that provide solar installation and related job 
4        training. It is a goal of this program that a minimum 
5        of 25% of the incentives for this program be allocated 
6        to projects located within environmental justice 
7        communities. The Agency shall reserve a portion of 
8        this program for projects that promote energy 
9        sovereignty through ownership of projects by 
10        low-income households, not-for-profit organizations 
11        providing services to low-income households, 
12        affordable housing owners, or community-based limited 
13        liability companies providing services to low-income 
14        households. Projects that feature energy ownership 
15        should ensure that local people have control of the 
16        project and reap benefits from the project over and 
17        above energy bill savings. The Agency may consider the 
18        inclusion of projects that promote ownership over time 
19        or that involve partial project ownership by 
20        communities, as promoting energy sovereignty. 
21        Incentives for projects that promote energy 
22        sovereignty may be higher than incentives for 
23        equivalent projects that do not promote energy 
24        sovereignty under this same program. 
25        The requirement that a qualified person, as defined in 
26    paragraph (1) of subsection (i) of this Section, install 
 
 
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1    photovoltaic devices does not apply to the Illinois Solar 
2    for All Program described in this subsection (b).
3        In addition to the programs outlined in paragraphs (A) 
4    through (E), the Agency and other parties may propose 
5    additional programs through the long-term renewable 
6    resources procurement plan Long-Term Renewable Resources 
7    Procurement Plan developed and approved under paragraph 
8    (5) of subsection (b) of Section 16-111.5 of the Public 
9    Utilities Act. Additional programs may target market 
10    segments not specified above and may also include 
11    incentives targeted to increase the uptake of 
12    nonphotovoltaic technologies by low-income customers, 
13    including energy storage paired with photovoltaics, if the 
14    Commission determines that the Illinois Solar for All 
15    Program would provide greater benefits to the public 
16    health and well-being of low-income residents through also 
17    supporting that additional program versus supporting 
18    programs already authorized. 
19        (3) Costs associated with the Illinois Solar for All 
20    Program and its components described in paragraph (2) of 
21    this subsection (b), including, but not limited to, costs 
22    associated with procuring experts, consultants, and the 
23    program administrator referenced in this subsection (b) 
24    and related incremental costs, costs related to income 
25    verification and facilitating customer participation in 
26    the program through referrals and other methods, costs 
 
 
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1    related to obtaining feedback on the program from parties 
2    that do not have a financial interest, and costs related 
3    to the evaluation of the Illinois Solar for All Program, 
4    may be paid for using monies in the Illinois Power Agency 
5    Renewable Energy Resources Fund, and funds allocated 
6    pursuant to subparagraph (O) of paragraph (1) of 
7    subsection (c) of Section 1-75, but the Agency or program 
8    administrator shall strive to minimize costs in the 
9    implementation of the program. The Agency or contracting 
10    electric utility shall purchase renewable energy credits 
11    from generation that is the subject of a contract under 
12    subparagraphs (A) through (E) of paragraph (2) of this 
13    subsection (b), and may pay for such renewable energy 
14    credits through an upfront payment per installed kilowatt 
15    of nameplate capacity paid once the device is 
16    interconnected at the distribution system level of the 
17    interconnecting utility and verified as energized. Unless 
18    otherwise provided in the Agency's long-term renewable 
19    resources procurement plan, payments Payments for 
20    renewable energy credits shall be in exchange for all 
21    renewable energy credits generated by the system during 
22    the first 15 years of operation and shall be structured to 
23    overcome barriers to participation in the solar market by 
24    the low-income community. The incentives provided for in 
25    this Section may be implemented through the pricing of 
26    renewable energy credits where the prices paid for the 
 
 
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1    credits are higher than the prices from programs offered 
2    under subsection (c) of Section 1-75 of this Act to 
3    account for the additional capital necessary to 
4    successfully access targeted market segments. The Agency 
5    or contracting electric utility shall retire any renewable 
6    energy credits purchased under this program and the 
7    credits shall count toward the obligation under subsection 
8    (c) of Section 1-75 of this Act for the electric utility to 
9    which the project is interconnected, if applicable.
10        The Agency shall direct that up to 5% of the funds 
11    available under the Illinois Solar for All Program to 
12    community-based groups and other qualifying organizations 
13    to assist in community-driven education efforts related to 
14    the Illinois Solar for All Program, including general 
15    energy education, job training program outreach efforts, 
16    and other activities deemed to be qualified by the Agency. 
17    Grassroots education funding shall not be used to support 
18    the marketing by solar project development firms and 
19    organizations, unless such education provides equal 
20    opportunities for all applicable firms and organizations.
21        The Agency may direct up to 25% of the funds currently 
22    allocated to subparagraphs (A), (C), and (E) of paragraph 
23    (2) toward the Illinois Storage for All Program, which 
24    provides incentives through grants, rebates, or other 
25    incentives to encourage development of energy storage 
26    colocated with photovoltaic distributed renewable energy 
 
 
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1    generation devices developed through the Illinois Solar 
2    for All Program. Any unused Storage for All funds during a 
3    program year may be reallocated to other Solar for All 
4    Program projects that are waitlisted or otherwise not 
5    selected due to funding limitation per the Agency's 
6    defined process. The Illinois Storage for All Program 
7    shall be available to current and future participants of 
8    the low-income single-family and multifamily subprogram 
9    described in subparagraphs (A) and (E) of paragraph (2), 
10    and the subprogram for nonprofit and public facilities 
11    described in subparagraph (C) of paragraph (2). If 
12    developed, the Illinois Storage for All Program may be 
13    designed to support community energy resilience, disaster 
14    preparedness, and energy bill reductions, particularly for 
15    residents of low-income and environmental justice 
16    communities. The Agency may propose the funding amount, 
17    structure, and details of the Illinois Storage for All 
18    Program in the Agency's long-term renewable resources 
19    procurement plan described in subsection (c) of Section 
20    1-75 of this Act and Section 16-111.5 of the Public 
21    Utilities Act, or through its energy storage resources 
22    procurement plan described in subsection (d-20) of Section 
23    1-75 of this Act. As part of the development of its initial 
24    energy storage resources procurement plan, the Agency 
25    shall engage stakeholders in the development of the 
26    Illinois Storage for All Program, including, but not 
 
 
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1    limited to, members of the Illinois Commission on 
2    Environmental Justice described in Section 10 of the 
3    Environmental Justice Act, representatives of approved 
4    vendors participating in the Illinois Solar for All 
5    Program, representatives of community-based 
6    organizations, and members of the Illinois Solar for All 
7    Stakeholder Advisory Group. The stakeholder process shall 
8    include, but not be limited to, an exploration of how to 
9    ensure that the distributed storage will be accessible to 
10    income-qualified households with zero upfront costs and in 
11    coordination with job training programs, as well as how 
12    the program may be supported by other programs or 
13    initiatives to maximize storage benefits and limit 
14    double-counting of incentives.    
15        (4) The Agency shall, consistent with the requirements 
16    of this subsection (b), propose the Illinois Solar for All 
17    Program terms, conditions, and requirements, including the 
18    prices to be paid for renewable energy credits, and which 
19    prices may be determined through a formula, through the 
20    development, review, and approval of the Agency's 
21    long-term renewable resources procurement plan described 
22    in subsection (c) of Section 1-75 of this Act and Section 
23    16-111.5 of the Public Utilities Act. In the course of the 
24    Commission proceeding initiated to review and approve the 
25    plan, including the Illinois Solar for All Program 
26    proposed by the Agency, a party may propose an additional 
 
 
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1    low-income solar or solar incentive program, or 
2    modifications to the programs proposed by the Agency, and 
3    the Commission may approve an additional program, or 
4    modifications to the Agency's proposed program, if the 
5    additional or modified program more effectively maximizes 
6    the benefits to low-income customers after taking into 
7    account all relevant factors, including, but not limited 
8    to, the extent to which a competitive market for 
9    low-income solar has developed. Following the Commission's 
10    approval of the Illinois Solar for All Program, the Agency 
11    or a party may propose adjustments to the program terms, 
12    conditions, and requirements, including the price offered 
13    to new systems, to ensure the long-term viability and 
14    success of the program. The Commission shall review and 
15    approve any modifications to the program through the plan 
16    revision process described in Section 16-111.5 of the 
17    Public Utilities Act.
18        (5) The Agency shall issue a request for 
19    qualifications for a third-party program administrator or 
20    administrators to administer all or a portion of the 
21    Illinois Solar for All Program. The third-party program 
22    administrator shall be chosen through a competitive bid 
23    process based on selection criteria and requirements 
24    developed by the Agency, including, but not limited to, 
25    experience in administering low-income energy programs and 
26    overseeing statewide clean energy or energy efficiency 
 
 
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1    services. If the Agency retains a program administrator or 
2    administrators to implement all or a portion of the 
3    Illinois Solar for All Program, each administrator shall 
4    periodically submit reports to the Agency and Commission 
5    for each program that it administers, at appropriate 
6    intervals to be identified by the Agency in its long-term 
7    renewable resources procurement plan, subject to 
8    Commission approval, provided that the reporting interval 
9    is at least an annual period quarterly. The third-party 
10    program administrator may be, but need not be, the same 
11    administrator as for the Adjustable Block program 
12    described in subparagraphs (K) through (M) of paragraph 
13    (1) of subsection (c) of Section 1-75. The Agency, through 
14    its long-term renewable resources procurement plan 
15    approval process, shall also determine if individual 
16    subprograms of the Illinois Solar for All Program are 
17    better served by a different or separate Program 
18    Administrator.
19        The third-party administrator's responsibilities 
20    shall also include facilitating placement for graduates of 
21    Illinois-based renewable energy-specific job training 
22    programs, including the Clean Jobs Workforce Network 
23    Program and the Illinois Climate Works Preapprenticeship 
24    Program administered by the Department of Commerce and 
25    Economic Opportunity and programs administered under 
26    Section 16-108.12 of the Public Utilities Act. To increase 
 
 
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1    the uptake of trainees by participating firms, the 
2    administrator shall also develop a web-based clearinghouse 
3    for information available to both job training program 
4    graduates and firms participating, directly or indirectly, 
5    in Illinois solar incentive programs. The program 
6    administrator shall also coordinate its activities with 
7    entities implementing electric and natural gas 
8    income-qualified energy efficiency programs, including 
9    customer referrals to and from such programs, and connect 
10    prospective low-income solar customers with any existing 
11    deferred maintenance programs where applicable. 
12        (6) The long-term renewable resources procurement plan 
13    shall also provide for an independent evaluation of the 
14    Illinois Solar for All Program. At least every 5 2 years, 
15    the Agency shall select an independent evaluator to review 
16    and report on the Illinois Solar for All Program and the 
17    performance of the third-party program administrator of 
18    the Illinois Solar for All Program. The evaluation shall 
19    be based on objective criteria developed through a public 
20    stakeholder process. The process shall include feedback 
21    and participation from Illinois Solar for All Program 
22    stakeholders, including participants and organizations in 
23    environmental justice and historically underserved 
24    communities. The report shall include a summary of the 
25    evaluation of the Illinois Solar for All Program based on 
26    the stakeholder developed objective criteria. The report 
 
 
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1    shall include the number of projects installed; the total 
2    installed capacity in kilowatts; the average cost per 
3    kilowatt of installed capacity to the extent reasonably 
4    obtainable by the Agency; the number of jobs or job 
5    opportunities created; economic, social, and environmental 
6    benefits created; and the total administrative costs 
7    expended by the Agency and program administrator to 
8    implement and evaluate the program. The report shall be 
9    prepared at least every 2 years and shall be delivered to 
10    the Commission and posted on the Agency's website, and 
11    shall be used, as needed, to revise the Illinois Solar for 
12    All Program. The Commission shall also consider the 
13    results of the evaluation as part of its review of the 
14    long-term renewable resources procurement plan under 
15    subsection (c) of Section 1-75 of this Act.
16        (7) If additional funding for the programs described 
17    in this subsection (b) is available under subsection (k) 
18    of Section 16-108 of the Public Utilities Act, then the 
19    Agency shall submit a procurement plan to the Commission 
20    no later than September 1, 2018, that proposes how the 
21    Agency will procure programs on behalf of the applicable 
22    utility. After notice and hearing, the Commission shall 
23    approve, or approve with modification, the plan no later 
24    than November 1, 2018.
25        (8) As part of the development and update of the 
26    long-term renewable resources procurement plan authorized 
 
 
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1    by subsection (c) of Section 1-75 of this Act, the Agency 
2    shall plan for: (A) actions to refer customers from the 
3    Illinois Solar for All Program to electric and natural gas 
4    income-qualified energy efficiency programs, and vice 
5    versa, with the goal of increasing participation in both 
6    of these programs; (B) effective procedures for data 
7    sharing, as needed, to effectuate referrals between the 
8    Illinois Solar for All Program and both electric and 
9    natural gas income-qualified energy efficiency programs, 
10    including sharing customer information directly with the 
11    utilities, as needed and appropriate; and (C) efforts to 
12    identify any existing deferred maintenance programs for 
13    which prospective Solar for All Program customers may be 
14    eligible and connect prospective customers for whom 
15    deferred maintenance is or may be a barrier to solar 
16    installation to those programs. 
17    Income verification for participation in the Illinois 
18Solar for All subprograms described in subparagraphs (A) and 
19(C) of paragraph (2) may include pathways for verification 
20that rely on self-attestation by the applicant if the 
21applicant's residence is located within a low-income or 
22environmental justice community as defined in this subsection 
23(b). The Agency shall proactively explore approaches that make 
24the income verification process less burdensome for residents 
25of low-income or environmental justice communities, as defined 
26in this subsection (b).    
 
 
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1    As used in this subsection (b), "low-income households" 
2means persons and families whose income does not exceed 80% of 
3area median income, adjusted for family size and revised every 
4year.
5    For the purposes of this subsection (b), the Agency shall 
6define "environmental justice community" based on the 
7methodologies and findings established by the Agency and the 
8Administrator for the Illinois Solar for All Program in its 
9initial long-term renewable resources procurement plan and as 
10updated by the Agency and the Administrator for the Illinois 
11Solar for All Program as part of the long-term renewable 
12resources procurement plan update. 
13    (b-5) After the receipt of all payments required by 
14Section 16-115D of the Public Utilities Act, no additional 
15funds shall be deposited into the Illinois Power Agency 
16Renewable Energy Resources Fund unless directed by order of 
17the Commission.
18    (b-10) After the receipt of all payments required by 
19Section 16-115D of the Public Utilities Act and payment in 
20full of all contracts executed by the Agency under subsections 
21(b) and (i) of this Section, if the balance of the Illinois 
22Power Agency Renewable Energy Resources Fund is under $5,000, 
23then the Fund shall be inoperative and any remaining funds and 
24any funds submitted to the Fund after that date, shall be 
25transferred to the Supplemental Low-Income Energy Assistance 
26Fund for use in the Low-Income Home Energy Assistance Program, 
 
 
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1as authorized by the Energy Assistance Act.
2    (b-15) The prevailing wage requirements set forth in the 
3Prevailing Wage Act apply to each project that is undertaken 
4pursuant to one or more of the programs of incentives and 
5initiatives described in subsection (b) of this Section and 
6for which a project application is submitted to the program 
7after June 30, 2023 (the effective date of Public Act 103-188)    
8this amendatory Act of the 103rd General Assembly, except (i) 
9projects that serve single-family or multi-family residential 
10buildings and (ii) projects with an aggregate capacity of less 
11than 100 kilowatts that serve houses of worship. The Agency 
12shall require verification that all construction performed on 
13a project by the renewable energy credit delivery contract 
14holder, its contractors, or its subcontractors relating to the 
15construction of the facility is performed by workers receiving 
16an amount for that work that is greater than or equal to the 
17general prevailing rate of wages as that term is defined in the 
18Prevailing Wage Act, and the Agency may adjust renewable 
19energy credit prices to account for increased labor costs.
20    In this subsection (b-15), "house of worship" has the 
21meaning given in subparagraph (Q) of paragraph (1) of 
22subsection (c) of Section 1-75. 
23    (c) (Blank).
24    (d) (Blank).
25    (e) All renewable energy credits procured using monies 
26from the Illinois Power Agency Renewable Energy Resources Fund 
 
 
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1shall be permanently retired.
2    (f) The selection of one or more third-party program 
3managers or administrators, the selection of the independent 
4evaluator, and the procurement processes described in this 
5Section are exempt from the requirements of the Illinois 
6Procurement Code, under Section 20-10 of that Code.
7    (g) All disbursements from the Illinois Power Agency 
8Renewable Energy Resources Fund shall be made only upon 
9warrants of the Comptroller drawn upon the Treasurer as 
10custodian of the Fund upon vouchers signed by the Director or 
11by the person or persons designated by the Director for that 
12purpose. The Comptroller is authorized to draw the warrant 
13upon vouchers so signed. The Treasurer shall accept all 
14warrants so signed and shall be released from liability for 
15all payments made on those warrants.
16    (h) The Illinois Power Agency Renewable Energy Resources 
17Fund shall not be subject to sweeps, administrative charges, 
18or chargebacks, including, but not limited to, those 
19authorized under Section 8h of the State Finance Act, that 
20would in any way result in the transfer of any funds from this 
21Fund to any other fund of this State or in having any such 
22funds utilized for any purpose other than the express purposes 
23set forth in this Section.
24    (h-5) The Agency may assess fees to each bidder to recover 
25the costs incurred in connection with a procurement process 
26held under this Section. Fees collected from bidders shall be 
 
 
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1deposited into the Illinois Power Agency Renewable Energy 
2Resources Fund. 
3    (i) Supplemental procurement process.
4        (1) Within 90 days after June 30, 2014 (the effective 
5    date of Public Act 98-672), the Agency shall develop a 
6    one-time supplemental procurement plan limited to the 
7    procurement of renewable energy credits, if available, 
8    from new or existing photovoltaics, including, but not 
9    limited to, distributed photovoltaic generation. Nothing 
10    in this subsection (i) requires procurement of wind 
11    generation through the supplemental procurement.
12        Renewable energy credits procured from new 
13    photovoltaics, including, but not limited to, distributed 
14    photovoltaic generation, under this subsection (i) must be 
15    procured from devices installed by a qualified person. In 
16    its supplemental procurement plan, the Agency shall 
17    establish contractually enforceable mechanisms for 
18    ensuring that the installation of new photovoltaics is 
19    performed by a qualified person.
20        For the purposes of this paragraph (1), "qualified 
21    person" means a person who performs installations of 
22    photovoltaics, including, but not limited to, distributed 
23    photovoltaic generation, and who: (A) has completed an 
24    apprenticeship as a journeyman electrician from a United 
25    States Department of Labor registered electrical 
26    apprenticeship and training program and received a 
 
 
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1    certification of satisfactory completion; or (B) does not 
2    currently meet the criteria under clause (A) of this 
3    paragraph (1), but is enrolled in a United States 
4    Department of Labor registered electrical apprenticeship 
5    program, provided that the person is directly supervised 
6    by a person who meets the criteria under clause (A) of this 
7    paragraph (1); or (C) has obtained one of the following 
8    credentials in addition to attesting to satisfactory 
9    completion of at least 5 years or 8,000 hours of 
10    documented hands-on electrical experience: (i) a North 
11    American Board of Certified Energy Practitioners (NABCEP) 
12    Installer Certificate for Solar PV; (ii) an Underwriters 
13    Laboratories (UL) PV Systems Installer Certificate; (iii) 
14    an Electronics Technicians Association, International 
15    (ETAI) Level 3 PV Installer Certificate; or (iv) an 
16    Associate in Applied Science degree from an Illinois 
17    Community College Board approved community college program 
18    in renewable energy or a distributed generation 
19    technology.
20        For the purposes of this paragraph (1), "directly 
21    supervised" means that there is a qualified person who 
22    meets the qualifications under clause (A) of this 
23    paragraph (1) and who is available for supervision and 
24    consultation regarding the work performed by persons under 
25    clause (B) of this paragraph (1), including a final 
26    inspection of the installation work that has been directly 
 
 
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1    supervised to ensure safety and conformity with applicable 
2    codes.
3        For the purposes of this paragraph (1), "install" 
4    means the major activities and actions required to 
5    connect, in accordance with applicable building and 
6    electrical codes, the conductors, connectors, and all 
7    associated fittings, devices, power outlets, or 
8    apparatuses mounted at the premises that are directly 
9    involved in delivering energy to the premises' electrical 
10    wiring from the photovoltaics, including, but not limited 
11    to, to distributed photovoltaic generation. 
12        The renewable energy credits procured pursuant to the 
13    supplemental procurement plan shall be procured using up 
14    to $30,000,000 from the Illinois Power Agency Renewable 
15    Energy Resources Fund. The Agency shall not plan to use 
16    funds from the Illinois Power Agency Renewable Energy 
17    Resources Fund in excess of the monies on deposit in such 
18    fund or projected to be deposited into such fund. The 
19    supplemental procurement plan shall ensure adequate, 
20    reliable, affordable, efficient, and environmentally 
21    sustainable renewable energy resources (including credits) 
22    at the lowest total cost over time, taking into account 
23    any benefits of price stability.
24        To the extent available, 50% of the renewable energy 
25    credits procured from distributed renewable energy 
26    generation shall come from devices of less than 25 
 
 
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1    kilowatts in nameplate capacity. Procurement of renewable 
2    energy credits from distributed renewable energy 
3    generation devices shall be done through multi-year 
4    contracts of no less than 5 years. The Agency shall create 
5    credit requirements for counterparties. In order to 
6    minimize the administrative burden on contracting 
7    entities, the Agency shall solicit the use of third 
8    parties to aggregate distributed renewable energy. These 
9    third parties shall enter into and administer contracts 
10    with individual distributed renewable energy generation 
11    device owners. An individual distributed renewable energy 
12    generation device owner shall have the ability to measure 
13    the output of his or her distributed renewable energy 
14    generation device.
15        In developing the supplemental procurement plan, the 
16    Agency shall hold at least one workshop open to the public 
17    within 90 days after June 30, 2014 (the effective date of 
18    Public Act 98-672) and shall consider any comments made by 
19    stakeholders or the public. Upon development of the 
20    supplemental procurement plan within this 90-day period, 
21    copies of the supplemental procurement plan shall be 
22    posted and made publicly available on the Agency's and 
23    Commission's websites. All interested parties shall have 
24    14 days following the date of posting to provide comment 
25    to the Agency on the supplemental procurement plan. All 
26    comments submitted to the Agency shall be specific, 
 
 
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1    supported by data or other detailed analyses, and, if 
2    objecting to all or a portion of the supplemental 
3    procurement plan, accompanied by specific alternative 
4    wording or proposals. All comments shall be posted on the 
5    Agency's and Commission's websites. Within 14 days 
6    following the end of the 14-day review period, the Agency 
7    shall revise the supplemental procurement plan as 
8    necessary based on the comments received and file its 
9    revised supplemental procurement plan with the Commission 
10    for approval.
11        (2) Within 5 days after the filing of the supplemental 
12    procurement plan at the Commission, any person objecting 
13    to the supplemental procurement plan shall file an 
14    objection with the Commission. Within 10 days after the 
15    filing, the Commission shall determine whether a hearing 
16    is necessary. The Commission shall enter its order 
17    confirming or modifying the supplemental procurement plan 
18    within 90 days after the filing of the supplemental 
19    procurement plan by the Agency.
20        (3) The Commission shall approve the supplemental 
21    procurement plan of renewable energy credits to be 
22    procured from new or existing photovoltaics, including, 
23    but not limited to, distributed photovoltaic generation, 
24    if the Commission determines that it will ensure adequate, 
25    reliable, affordable, efficient, and environmentally 
26    sustainable electric service in the form of renewable 
 
 
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1    energy credits at the lowest total cost over time, taking 
2    into account any benefits of price stability.
3        (4) The supplemental procurement process under this 
4    subsection (i) shall include each of the following 
5    components:
6            (A) Procurement administrator. The Agency may 
7        retain a procurement administrator in the manner set 
8        forth in item (2) of subsection (a) of Section 1-75 of 
9        this Act to conduct the supplemental procurement or 
10        may elect to use the same procurement administrator 
11        administering the Agency's annual procurement under 
12        Section 1-75.
13            (B) Procurement monitor. The procurement monitor 
14        retained by the Commission pursuant to Section 
15        16-111.5 of the Public Utilities Act shall:
16                (i) monitor interactions among the procurement 
17            administrator and bidders and suppliers;
18                (ii) monitor and report to the Commission on 
19            the progress of the supplemental procurement 
20            process;
21                (iii) provide an independent confidential 
22            report to the Commission regarding the results of 
23            the procurement events;
24                (iv) assess compliance with the procurement 
25            plan approved by the Commission for the 
26            supplemental procurement process;
 
 
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1                (v) preserve the confidentiality of supplier 
2            and bidding information in a manner consistent 
3            with all applicable laws, rules, regulations, and 
4            tariffs;
5                (vi) provide expert advice to the Commission 
6            and consult with the procurement administrator 
7            regarding issues related to procurement process 
8            design, rules, protocols, and policy-related 
9            matters;
10                (vii) consult with the procurement 
11            administrator regarding the development and use of 
12            benchmark criteria, standard form contracts, 
13            credit policies, and bid documents; and
14                (viii) perform, with respect to the 
15            supplemental procurement process, any other 
16            procurement monitor duties specifically delineated 
17            within subsection (i) of this Section. 
18            (C) Solicitation, prequalification, and 
19        registration of bidders. The procurement administrator 
20        shall disseminate information to potential bidders to 
21        promote a procurement event, notify potential bidders 
22        that the procurement administrator may enter into a 
23        post-bid price negotiation with bidders that meet the 
24        applicable benchmarks, provide supply requirements, 
25        and otherwise explain the competitive procurement 
26        process. In addition to such other publication as the 
 
 
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1        procurement administrator determines is appropriate, 
2        this information shall be posted on the Agency's and 
3        the Commission's websites. The procurement 
4        administrator shall also administer the 
5        prequalification process, including evaluation of 
6        credit worthiness, compliance with procurement rules, 
7        and agreement to the standard form contract developed 
8        pursuant to item (D) of this paragraph (4). The 
9        procurement administrator shall then identify and 
10        register bidders to participate in the procurement 
11        event.
12            (D) Standard contract forms and credit terms and 
13        instruments. The procurement administrator, in 
14        consultation with the Agency, the Commission, and 
15        other interested parties and subject to Commission 
16        oversight, shall develop and provide standard contract 
17        forms for the supplier contracts that meet generally 
18        accepted industry practices as well as include any 
19        applicable State of Illinois terms and conditions that 
20        are required for contracts entered into by an agency 
21        of the State of Illinois. Standard credit terms and 
22        instruments that meet generally accepted industry 
23        practices shall be similarly developed. Contracts for 
24        new photovoltaics shall include a provision attesting 
25        that the supplier will use a qualified person for the 
26        installation of the device pursuant to paragraph (1) 
 
 
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1        of subsection (i) of this Section. The procurement 
2        administrator shall make available to the Commission 
3        all written comments it receives on the contract 
4        forms, credit terms, or instruments. If the 
5        procurement administrator cannot reach agreement with 
6        the parties as to the contract terms and conditions, 
7        the procurement administrator must notify the 
8        Commission of any disputed terms and the Commission 
9        shall resolve the dispute. The terms of the contracts 
10        shall not be subject to negotiation by winning 
11        bidders, and the bidders must agree to the terms of the 
12        contract in advance so that winning bids are selected 
13        solely on the basis of price.
14            (E) Requests for proposals; competitive 
15        procurement process. The procurement administrator 
16        shall design and issue requests for proposals to 
17        supply renewable energy credits in accordance with the 
18        supplemental procurement plan, as approved by the 
19        Commission. The requests for proposals shall set forth 
20        a procedure for sealed, binding commitment bidding 
21        with pay-as-bid settlement, and provision for 
22        selection of bids on the basis of price, provided, 
23        however, that no bid shall be accepted if it exceeds 
24        the benchmark developed pursuant to item (F) of this 
25        paragraph (4).
26            (F) Benchmarks. Benchmarks for each product to be 
 
 
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1        procured shall be developed by the procurement 
2        administrator in consultation with Commission staff, 
3        the Agency, and the procurement monitor for use in 
4        this supplemental procurement.
5            (G) A plan for implementing contingencies in the 
6        event of supplier default, Commission rejection of 
7        results, or any other cause.
8        (5) Within 2 business days after opening the sealed 
9    bids, the procurement administrator shall submit a 
10    confidential report to the Commission. The report shall 
11    contain the results of the bidding for each of the 
12    products along with the procurement administrator's 
13    recommendation for the acceptance and rejection of bids 
14    based on the price benchmark criteria and other factors 
15    observed in the process. The procurement monitor also 
16    shall submit a confidential report to the Commission 
17    within 2 business days after opening the sealed bids. The 
18    report shall contain the procurement monitor's assessment 
19    of bidder behavior in the process as well as an assessment 
20    of the procurement administrator's compliance with the 
21    procurement process and rules. The Commission shall review 
22    the confidential reports submitted by the procurement 
23    administrator and procurement monitor and shall accept or 
24    reject the recommendations of the procurement 
25    administrator within 2 business days after receipt of the 
26    reports.
 
 
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1        (6) Within 3 business days after the Commission 
2    decision approving the results of a procurement event, the 
3    Agency shall enter into binding contractual arrangements 
4    with the winning suppliers using the standard form 
5    contracts.
6        (7) The names of the successful bidders and the 
7    average of the winning bid prices for each contract type 
8    and for each contract term shall be made available to the 
9    public within 2 days after the supplemental procurement 
10    event. The Commission, the procurement monitor, the 
11    procurement administrator, the Agency, and all 
12    participants in the procurement process shall maintain the 
13    confidentiality of all other supplier and bidding 
14    information in a manner consistent with all applicable 
15    laws, rules, regulations, and tariffs. Confidential 
16    information, including the confidential reports submitted 
17    by the procurement administrator and procurement monitor 
18    pursuant to this Section, shall not be made publicly 
19    available and shall not be discoverable by any party in 
20    any proceeding, absent a compelling demonstration of need, 
21    nor shall those reports be admissible in any proceeding 
22    other than one for law enforcement purposes.
23        (8) The supplemental procurement provided in this 
24    subsection (i) shall not be subject to the requirements 
25    and limitations of subsections (c) and (d) of this 
26    Section.
 
 
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1        (9) Expenses incurred in connection with the 
2    procurement process held pursuant to this Section, 
3    including, but not limited to, the cost of developing the 
4    supplemental procurement plan, the procurement 
5    administrator, procurement monitor, and the cost of the 
6    retirement of renewable energy credits purchased pursuant 
7    to the supplemental procurement shall be paid for from the 
8    Illinois Power Agency Renewable Energy Resources Fund. The 
9    Agency shall enter into an interagency agreement with the 
10    Commission to reimburse the Commission for its costs 
11    associated with the procurement monitor for the 
12    supplemental procurement process. 
13(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23; 
14103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; revised 
156-23-25.)
 
16    (20 ILCS 3855/1-75)
17    Sec. 1-75. Planning and Procurement Bureau. The Planning 
18and Procurement Bureau has the following duties and 
19responsibilities:
20    (a) The Planning and Procurement Bureau shall each year, 
21beginning in 2008, develop procurement plans and conduct 
22competitive procurement processes in accordance with the 
23requirements of Section 16-111.5 of the Public Utilities Act 
24for the eligible retail customers of electric utilities that 
25on December 31, 2005 provided electric service to at least 
 
 
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1100,000 customers in Illinois. Beginning with the delivery 
2year commencing on June 1, 2017, the Planning and Procurement 
3Bureau shall develop plans and processes for the procurement 
4of zero emission credits from zero emission facilities in 
5accordance with the requirements of subsection (d-5) of this 
6Section. Beginning on the effective date of this amendatory 
7Act of the 102nd General Assembly, the Planning and 
8Procurement Bureau shall develop plans and processes for the 
9procurement of carbon mitigation credits from carbon-free 
10energy resources in accordance with the requirements of 
11subsection (d-10) of this Section. The Planning and 
12Procurement Bureau shall also develop procurement plans and 
13conduct competitive procurement processes in accordance with 
14the requirements of Section 16-111.5 of the Public Utilities 
15Act for the eligible retail customers of small 
16multi-jurisdictional electric utilities that (i) on December 
1731, 2005 served less than 100,000 customers in Illinois and 
18(ii) request a procurement plan for their Illinois 
19jurisdictional load. This Section shall not apply to a small 
20multi-jurisdictional utility until such time as a small 
21multi-jurisdictional utility requests the Agency to prepare a 
22procurement plan for their Illinois jurisdictional load. For 
23the purposes of this Section, the term "eligible retail 
24customers" has the same definition as found in Section 
2516-111.5(a) of the Public Utilities Act.
26    Beginning with the plan or plans to be implemented in the 
 
 
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12017 delivery year, the Agency shall no longer include the 
2procurement of renewable energy resources in the annual 
3procurement plans required by this subsection (a), except as 
4provided in subsection (q) of Section 16-111.5 of the Public 
5Utilities Act, and shall instead develop a long-term renewable 
6resources procurement plan in accordance with subsection (c) 
7of this Section and Section 16-111.5 of the Public Utilities 
8Act. 
9    In accordance with subsection (c-5) of this Section, the 
10Planning and Procurement Bureau shall oversee the procurement 
11by electric utilities that served more than 300,000 retail 
12customers in this State as of January 1, 2019 of renewable 
13energy credits from new utility-scale solar projects to be 
14installed, along with energy storage facilities, at or 
15adjacent to the sites of electric generating facilities that, 
16as of January 1, 2016, burned coal as their primary fuel 
17source. 
18        (1) The Agency shall each year, beginning in 2008, as 
19    needed, issue a request for qualifications for experts or 
20    expert consulting firms to develop the procurement plans 
21    in accordance with Section 16-111.5 of the Public 
22    Utilities Act. In order to qualify an expert or expert 
23    consulting firm must have:
24            (A) direct previous experience assembling 
25        large-scale power supply plans or portfolios for 
26        end-use customers;
 
 
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1            (B) an advanced degree in economics, mathematics, 
2        engineering, risk management, or a related area of 
3        study;
4            (C) 10 years of experience in the electricity 
5        sector, including managing supply risk;
6            (D) expertise in wholesale electricity market 
7        rules, including those established by the Federal 
8        Energy Regulatory Commission and regional transmission 
9        organizations;
10            (E) expertise in credit protocols and familiarity 
11        with contract protocols;
12            (F) adequate resources to perform and fulfill the 
13        required functions and responsibilities; and
14            (G) the absence of a conflict of interest and 
15        inappropriate bias for or against potential bidders or 
16        the affected electric utilities.
17        (2) The Agency shall each year, as needed, issue a 
18    request for qualifications for a procurement administrator 
19    to conduct the competitive procurement processes in 
20    accordance with Section 16-111.5 of the Public Utilities 
21    Act. In order to qualify an expert or expert consulting 
22    firm must have:
23            (A) direct previous experience administering a 
24        large-scale competitive procurement process;
25            (B) an advanced degree in economics, mathematics, 
26        engineering, or a related area of study;
 
 
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1            (C) 10 years of experience in the electricity 
2        sector, including risk management experience;
3            (D) expertise in wholesale electricity market 
4        rules, including those established by the Federal 
5        Energy Regulatory Commission and regional transmission 
6        organizations; 
7            (E) expertise in credit and contract protocols;
8            (F) adequate resources to perform and fulfill the 
9        required functions and responsibilities; and
10            (G) the absence of a conflict of interest and 
11        inappropriate bias for or against potential bidders or 
12        the affected electric utilities.
13        (3) The Agency shall provide affected utilities and 
14    other interested parties with the lists of qualified 
15    experts or expert consulting firms identified through the 
16    request for qualifications processes that are under 
17    consideration to develop the procurement plans and to 
18    serve as the procurement administrator. The Agency shall 
19    also provide each qualified expert's or expert consulting 
20    firm's response to the request for qualifications. All 
21    information provided under this subparagraph shall also be 
22    provided to the Commission. The Agency may provide by rule 
23    for fees associated with supplying the information to 
24    utilities and other interested parties. These parties 
25    shall, within 5 business days, notify the Agency in 
26    writing if they object to any experts or expert consulting 
 
 
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1    firms on the lists. Objections shall be based on:
2            (A) failure to satisfy qualification criteria;
3            (B) identification of a conflict of interest; or
4            (C) evidence of inappropriate bias for or against 
5        potential bidders or the affected utilities.
6        The Agency shall remove experts or expert consulting 
7    firms from the lists within 10 days if there is a 
8    reasonable basis for an objection and provide the updated 
9    lists to the affected utilities and other interested 
10    parties. If the Agency fails to remove an expert or expert 
11    consulting firm from a list, an objecting party may seek 
12    review by the Commission within 5 days thereafter by 
13    filing a petition, and the Commission shall render a 
14    ruling on the petition within 10 days. There is no right of 
15    appeal of the Commission's ruling.
16        (4) The Agency shall issue requests for proposals to 
17    the qualified experts or expert consulting firms to 
18    develop a procurement plan for the affected utilities and 
19    to serve as procurement administrator.
20        (5) The Agency shall select an expert or expert 
21    consulting firm to develop procurement plans based on the 
22    proposals submitted and shall award contracts of up to 5 
23    years to those selected.
24        (6) The Agency shall select an expert or expert 
25    consulting firm, with approval of the Commission, to serve 
26    as procurement administrator based on the proposals 
 
 
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1    submitted. If the Commission rejects, within 5 days, the 
2    Agency's selection, the Agency shall submit another 
3    recommendation within 3 days based on the proposals 
4    submitted. The Agency shall award a 5-year contract to the 
5    expert or expert consulting firm so selected with 
6    Commission approval.
7    (b) The experts or expert consulting firms retained by the 
8Agency shall, as appropriate, prepare procurement plans, and 
9conduct a competitive procurement process as prescribed in 
10Section 16-111.5 of the Public Utilities Act, to ensure 
11adequate, reliable, affordable, efficient, and environmentally 
12sustainable electric service at the lowest total cost over 
13time, taking into account any benefits of price stability, for 
14eligible retail customers of electric utilities that on 
15December 31, 2005 provided electric service to at least 
16100,000 customers in the State of Illinois, and for eligible 
17Illinois retail customers of small multi-jurisdictional 
18electric utilities that (i) on December 31, 2005 served less 
19than 100,000 customers in Illinois and (ii) request a 
20procurement plan for their Illinois jurisdictional load.
21    (c) Renewable portfolio standard.
22        (1)(A) The Agency shall develop a long-term renewable 
23    resources procurement plan that shall include procurement 
24    programs and competitive procurement events necessary to 
25    meet the goals set forth in this subsection (c). The 
26    initial long-term renewable resources procurement plan 
 
 
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1    shall be released for comment no later than 160 days after 
2    June 1, 2017 (the effective date of Public Act 99-906). 
3    The Agency shall review, and may revise on an expedited 
4    basis, the long-term renewable resources procurement plan 
5    at least every 2 years, which shall be conducted in 
6    conjunction with the procurement plan under Section 
7    16-111.5 of the Public Utilities Act to the extent 
8    practicable to minimize administrative expense. No later 
9    than 120 days after the effective date of this amendatory 
10    Act of the 103rd General Assembly, the Agency shall 
11    release for comment a revision to the long-term renewable 
12    resources procurement plan, updating elements of the most 
13    recently approved plan as needed to comply with this 
14    amendatory Act of the 103rd General Assembly, and any 
15    long-term renewable resources procurement plan update 
16    published by the Agency but not yet approved by the 
17    Illinois Commerce Commission shall be withdrawn. The 
18    long-term renewable resources procurement plans shall be 
19    subject to review and approval by the Commission under 
20    Section 16-111.5 of the Public Utilities Act.
21        (B) Subject to subparagraph (F) of this paragraph (1), 
22    the long-term renewable resources procurement plan shall 
23    attempt to meet the goals for procurement of renewable 
24    energy credits at levels of at least the following overall 
25    percentages: 13% by the 2017 delivery year; increasing by 
26    at least 1.5% each delivery year thereafter to at least 
 
 
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1    25% by the 2025 delivery year; increasing by at least 3% 
2    each delivery year thereafter to at least 40% by the 2030 
3    delivery year, and continuing at no less than 40% for each 
4    delivery year thereafter. The Agency shall attempt to 
5    procure 50% by delivery year 2040. The Agency shall 
6    determine the annual increase between delivery year 2030 
7    and delivery year 2040, if any, taking into account energy 
8    demand, other energy resources, and other public policy 
9    goals. In the event of a conflict between these goals and 
10    the new wind, new photovoltaic, new geothermal heating and 
11    cooling, and hydropower procurement requirements described 
12    in items (i) through (iii) of subparagraph (C) of this 
13    paragraph (1), the long-term plan shall prioritize 
14    compliance with the new wind, new photovoltaic, new 
15    geothermal heating and cooling, and hydropower procurement 
16    requirements described in items (i) through (iii) of 
17    subparagraph (C) of this paragraph (1) over the annual 
18    percentage targets described in this subparagraph (B). The 
19    Agency shall not comply with the annual percentage targets 
20    described in this subparagraph (B) by procuring renewable 
21    energy credits that are unlikely to lead to the 
22    development of new renewable resources or new, modernized, 
23    or retooled hydropower facilities. 
24        For the delivery year beginning June 1, 2017, 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 13% of each utility's load for eligible retail 
3    customers and 13% 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 50% 
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, 2018, the 
9    procurement plan shall attempt to include, subject to the 
10    prioritization outlined in this subparagraph (B), 
11    cost-effective renewable energy resources equal to at 
12    least 14.5% of each utility's load for eligible retail 
13    customers and 14.5% of the applicable portion of each 
14    utility's load for retail customers who are not eligible 
15    retail customers, which applicable portion shall equal 75% 
16    of the utility's load for retail customers who are not 
17    eligible retail customers on February 28, 2017. 
18        For the delivery year beginning June 1, 2019, and for 
19    each year thereafter, the procurement plans shall attempt 
20    to include, subject to the prioritization outlined in this 
21    subparagraph (B), cost-effective renewable energy 
22    resources equal to a minimum percentage of each utility's 
23    load for all retail customers as follows: 16% by June 1, 
24    2019; increasing by 1.5% each year thereafter to 25% by 
25    June 1, 2025; and 25% by June 1, 2026; increasing by at 
26    least 3% each delivery year thereafter to at least 40% by 
 
 
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1    the 2030 delivery year, and continuing at no less than 40% 
2    for each delivery year thereafter. The Agency shall 
3    attempt to procure 50% by delivery year 2040. The Agency 
4    shall determine the annual increase between delivery year 
5    2030 and delivery year 2040, if any, taking into account 
6    energy demand, other energy resources, and other public 
7    policy goals. 
8        For each delivery year, the Agency shall first 
9    recognize each utility's obligations for that delivery 
10    year under existing contracts. Any renewable energy 
11    credits under existing contracts, including renewable 
12    energy credits as part of renewable energy resources, 
13    shall be used to meet the goals set forth in this 
14    subsection (c) for the delivery year. 
15        (C) The long-term renewable resources procurement plan 
16    described in subparagraph (A) of this paragraph (1) shall 
17    include the procurement of renewable energy credits from 
18    new projects pursuant to the following terms: 
19            (i) At least 10,000,000 renewable energy credits 
20        delivered annually by the end of the 2021 delivery 
21        year, and increasing ratably to reach 45,000,000 
22        renewable energy credits delivered annually from new 
23        wind and solar projects, from repowered wind projects, 
24        or from retooled hydropower facilities by the end of 
25        delivery year 2030 such that the goals in subparagraph 
26        (B) of this paragraph (1) are met entirely by 
 
 
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1        procurements of renewable energy credits from new wind 
2        and photovoltaic projects. Of that amount, to the 
3        extent possible, the Agency shall endeavor to procure 
4        45% from new and repowered wind and hydropower 
5        projects and shall procure at least 55% from 
6        photovoltaic projects. Of the amount to be procured 
7        from photovoltaic projects, the Agency shall procure: 
8        at least 50% from solar photovoltaic projects using 
9        the program outlined in subparagraph (K) of this 
10        paragraph (1) from distributed renewable energy 
11        generation devices or community renewable generation 
12        projects; at least 47% from utility-scale solar 
13        projects; at least 3% from brownfield site 
14        photovoltaic projects that are not community renewable 
15        generation projects. The Agency may propose 
16        adjustments to these percentages, including 
17        establishing percentage-based goals for the 
18        procurement of renewable energy credits from 
19        modernized or retooled hydropower facilities and 
20        repowered wind projects, through its long-term 
21        renewable resources plan described in subparagraph (A) 
22        of this paragraph (1) as necessary based on developer 
23        interest, market conditions, budget considerations, 
24        resource adequacy needs, or other factors. 
25        Notwithstanding the percentage-based goals as 
26        described in this Section, the Agency shall develop a 
 
 
10400SB0025ham004- 205 -LRB104 16098 AAS 29398 a

1        Geothermal Homes and Businesses Program for the 
2        procurement of renewable energy credits from 
3        geothermal heating and cooling systems.    
4            In developing the long-term renewable resources 
5        procurement plan, the Agency shall consider other 
6        approaches, in addition to competitive procurements, 
7        that can be used to procure renewable energy credits 
8        from brownfield site photovoltaic projects and thereby 
9        help return blighted or contaminated land to 
10        productive use while enhancing public health and the 
11        well-being of Illinois residents, including those in 
12        environmental justice communities, as defined using 
13        existing methodologies and findings used by the Agency 
14        and its Administrator in its Illinois Solar for All 
15        Program. The Agency shall also consider other 
16        approaches, in addition to competitive procurements, 
17        to procure renewable energy credits from new and 
18        existing hydropower facilities to support the 
19        development and maintenance of these facilities. The 
20        Agency shall explore options to convert existing dams 
21        but shall not consider approaches to develop new dams 
22        where they do not already exist. To encourage the 
23        continued operation of utility-scale wind projects, 
24        the Agency shall consider and may propose other 
25        approaches in addition to competitive procurements to 
26        procure renewable energy credits from repowered wind 
 
 
10400SB0025ham004- 206 -LRB104 16098 AAS 29398 a

1        projects. 
2            (ii) In any given delivery year, if forecasted 
3        expenses are less than the maximum budget available 
4        under subparagraph (E) of this paragraph (1), the 
5        Agency shall continue to procure new renewable energy 
6        credits until that budget is exhausted in the manner 
7        outlined in item (i) of this subparagraph (C).
8            (iii) For purposes of this Section:
9            "New wind projects" means wind renewable energy 
10        facilities that are energized after June 1, 2017 for 
11        the delivery year commencing June 1, 2017.
12            "New photovoltaic projects" means photovoltaic 
13        renewable energy facilities that are energized after 
14        June 1, 2017. Photovoltaic projects developed under 
15        Section 1-56 of this Act shall not apply towards the 
16        new photovoltaic project requirements in this 
17        subparagraph (C). 
18            "Repowered wind projects" means utility-scale wind 
19        projects featuring the removal, replacement, or 
20        expansion of turbines at an existing project site, as 
21        defined in the long-term renewable resources 
22        procurement plan, after the effective date of this 
23        amendatory Act of the 103rd General Assembly. 
24        Renewable energy credit contract awards used to 
25        support repowered wind projects shall only cover the 
26        incremental increase in facility electricity 
 
 
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1        production resultant from repowering. 
2            "Geothermal heating and cooling system" means a 
3        system located in this State that meets all of the 
4        following requirements:
5                (I) the system exchanges thermal energy from 
6            groundwater or a shallow ground source to generate 
7            thermal energy through an electric geothermal heat 
8            pump or a system of electric geothermal heat pumps 
9            interconnected with any geothermal extraction 
10            facility that is (1) a closed loop or a series of 
11            closed loop systems in which fluid is permanently 
12            confined within a pipe or tubing and does not come 
13            in contact with the outside environment or (2) an 
14            open loop system in which ground or surface water 
15            is circulated in an environmentally safe manner 
16            directly into the facility and returned to the 
17            same aquifer or surface water source;
18                (II) the system meets or exceeds federal 
19            Energy Star product specification standards for 
20            Geothermal Heat Pumps established on January 1, 
21            2012, as clarified by the Environmental Protection 
22            Agency guidance document released on February 28, 
23            2012 entitled "Clarification to the Geothermal 
24            Heat Pump Verification Testing Requirements and 
25            Basic Model Group Definition", or any successor 
26            standards that meet or exceed these standards;
 
 
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1                (III) the system replaces or displaces less 
2            efficient space or water heating systems, 
3            regardless of fuel type;
4                (IV) the system replaces or displaces less 
5            efficient space cooling systems, when applicable;
6                (V) the system does not feed electricity back 
7            to the grid, as defined at the level of the 
8            geothermal heat pump; and
9                (VI) the system became operational on or after 
10            the effective date of this amendatory Act of the 
11            104th General Assembly.    
12            For purposes of calculating whether the Agency has 
13        procured enough new wind and solar renewable energy 
14        credits required by this subparagraph (C), renewable 
15        energy facilities that have a multi-year renewable 
16        energy credit delivery contract with the utility 
17        through at least delivery year 2030 shall be 
18        considered new, however no renewable energy credits 
19        from contracts entered into before June 1, 2021 shall 
20        be used to calculate whether the Agency has procured 
21        the correct proportion of new wind and new solar 
22        contracts described in this subparagraph (C) for 
23        delivery year 2021 and thereafter.
24            (iv) The Agency may implement additional measures, 
25        including eligibility requirements, to ensure that new 
26        wind projects and new photovoltaic projects supported 
 
 
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1        through renewable energy credit contract awards are a 
2        result of a contract award and are otherwise developed 
3        pursuant to the financial certainty provided through a 
4        contract award.
5        (D) Renewable energy credits shall be cost effective. 
6    For purposes of this subsection (c), "cost effective" 
7    means that the costs of procuring renewable energy 
8    resources do not cause the limit stated in subparagraph 
9    (E) of this paragraph (1) to be exceeded and, for 
10    renewable energy credits procured through a competitive 
11    procurement event, do not exceed benchmarks based on 
12    market prices for like products in the region. For 
13    purposes of this subsection (c), "like products" means 
14    contracts for renewable energy credits from the same or 
15    substantially similar technology, same or substantially 
16    similar vintage (new or existing), the same or 
17    substantially similar quantity, and the same or 
18    substantially similar contract length and structure. 
19    Benchmarks shall reflect development, financing, or 
20    related costs resulting from requirements imposed through 
21    other provisions of State law, including, but not limited 
22    to, requirements in subparagraphs (P) and (Q) of this 
23    paragraph (1) and the Renewable Energy Facilities 
24    Agricultural Impact Mitigation Act. Confidential 
25    benchmarks shall be developed by the procurement 
26    administrator, in consultation with the Commission staff, 
 
 
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1    Agency staff, and the procurement monitor and shall be 
2    subject to Commission review and approval. If price 
3    benchmarks for like products in the region are not 
4    available, the procurement administrator shall establish 
5    price benchmarks based on publicly available data on 
6    regional technology costs and expected current and future 
7    regional energy prices. The benchmarks in this Section 
8    shall not be used to curtail or otherwise reduce 
9    contractual obligations entered into by or through the 
10    Agency prior to June 1, 2017 (the effective date of Public 
11    Act 99-906). 
12        (E) For purposes of this subsection (c), the required 
13    procurement of cost-effective renewable energy resources 
14    for a particular year commencing prior to June 1, 2017 
15    shall be measured as a percentage of the actual amount of 
16    electricity (megawatt-hours) supplied by the electric 
17    utility to eligible retail customers in the delivery year 
18    ending immediately prior to the procurement, and, for 
19    delivery years commencing on and after June 1, 2017, the 
20    required procurement of cost-effective renewable energy 
21    resources for a particular year shall be measured as a 
22    percentage of the actual amount of electricity 
23    (megawatt-hours) delivered by the electric utility in the 
24    delivery year ending immediately prior to the procurement, 
25    to all retail customers in its service territory. For 
26    purposes of this subsection (c), the amount paid per 
 
 
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1    kilowatthour means the total amount paid for electric 
2    service expressed on a per kilowatthour basis. For 
3    purposes of this subsection (c), the total amount paid for 
4    electric service includes without limitation amounts paid 
5    for supply, transmission, capacity, distribution, 
6    surcharges, and add-on taxes. 
7        Notwithstanding the requirements of this subsection 
8    (c), and except as provided in subparagraph (E-5) of 
9    paragraph (1) of this subsection (c) or except as 
10    otherwise authorized by the Commission in its approval of 
11    the integrated resource plan under Section 16-202 of the 
12    Public Utilities Act, the total of renewable energy 
13    resources procured under the procurement plan for any 
14    single year shall be subject to the limitations of this 
15    subparagraph (E). Such procurement shall be reduced for 
16    all retail customers based on the amount necessary to 
17    limit the annual estimated average net increase due to the 
18    costs of these resources included in the amounts paid by 
19    eligible retail customers in connection with electric 
20    service to no more than 4.25% of the amount paid per 
21    kilowatthour by those customers during the year ending May 
22    31, 2009, adjusted annually for inflation starting with 
23    the first adjustment in the delivery year commencing June 
24    1, 2026. For the purposes of this Section, the inflation 
25    adjustment shall not be accrued or applied retroactively 
26    prior to the effective date of this amendatory Act of the 
 
 
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1    104th General Assembly and shall apply prospectively 
2    starting in 2025. The limitation shall be increased by an 
3    additional 1.65 percentage points of the amount paid per 
4    kilowatthour by eligible retail customers during the year 
5    ending May 31, 2009 starting with the delivery year 
6    commencing June 1, 2027. To arrive at a maximum dollar 
7    amount of renewable energy resources to be procured for 
8    the particular delivery year, the resulting per 
9    kilowatthour amount shall be applied to the actual amount 
10    of kilowatthours of electricity delivered, or applicable 
11    portion of such amount as specified in paragraph (1) of 
12    this subsection (c), as applicable, by the electric 
13    utility in the delivery year immediately prior to the 
14    procurement to all retail customers in its service 
15    territory. The calculations required by this subparagraph 
16    (E) shall be made only once for each delivery year at the 
17    time that the renewable energy resources are procured. 
18    Once the determination as to the amount of renewable 
19    energy resources to procure is made based on the 
20    calculations set forth in this subparagraph (E) and the 
21    contracts procuring those amounts are executed between the 
22    seller and applicable electric utility, no subsequent rate 
23    impact determinations shall be made and no adjustments to 
24    those contract amounts shall be allowed. As provided in 
25    subparagraph (E-5) of paragraph (1) of this subsection 
26    (c), the seller shall be entitled to full, prompt, and 
 
 
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1    uninterrupted payment under the applicable contract 
2    notwithstanding the application of this subparagraph (E), 
3    and all costs incurred under such contracts shall be fully 
4    recoverable by the electric utility as provided in this 
5    Section. 
6        (E-5) If, for a particular delivery year, the 
7    limitation on the amount of renewable energy resources to 
8    be procured, as calculated pursuant to subparagraph (E) of 
9    paragraph (1) of this subsection (c), would result in an 
10    insufficient collection of funds to fully pay amounts due 
11    to a seller under existing contracts executed under this 
12    Section or executed under Section 1-56 of this Act, then 
13    the following provisions shall apply to ensure full and 
14    uninterrupted payment is made to such seller or sellers:
15            (i) If the electric utility has retained unspent 
16        funds in an interest-bearing account as prescribed in 
17        subsection (k) of Section 16-108 of the Public 
18        Utilities Act, then the utility shall use those funds 
19        to remit full payment to the sellers to ensure prompt 
20        and uninterrupted payment of existing contractual 
21        obligation.
22            (ii) If the funds described in item (i) of this 
23        subparagraph (E-5) are insufficient to satisfy all 
24        existing contractual obligations, then the electric 
25        utility shall, nonetheless, remit full payment to the 
26        sellers to ensure prompt and uninterrupted payment of 
 
 
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1        existing contractual obligations, provided that the 
2        full costs shall be recoverable by the utility in 
3        accordance with part (ee) of item (iv) of this 
4        subsection (E-5).
5            (iii) The Agency shall promptly notify the 
6        Commission that existing contractual obligations are 
7        reasonably expected to exceed the maximum collection 
8        authorized under subparagraph (E) of paragraph (1) of 
9        this subsection (c) for the applicable delivery year. 
10        The Agency shall also explain and confirm how the 
11        operation of items (i) and (ii) of this subparagraph 
12        (E-5) ensures that the electric utility will continue 
13        to make prompt and uninterrupted payment under 
14        existing contractual obligations. The Agency shall 
15        provide this information to the Commission through a 
16        notice filed in the Commission docket approving the 
17        Agency's operative Long-Term Renewable Resources 
18        Procurement Plan that includes the applicable delivery 
19        year.
20            (iv) The Agency shall suspend or reduce new 
21        contract awards for the procurement of renewable 
22        energy credits until an Agency determination is made 
23        under subparagraph (E) that additional procurements 
24        would not cause the rate impact limitation of 
25        subparagraph (E) to be exceeded. At least once 
26        annually after the notice provided for in item (iii) 
 
 
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1        of this subparagraph (E-5) is made, the Agency shall 
2        analyze existing contract obligations, projected 
3        prices for indexed renewable energy credit contracts 
4        executed under item (v) of subparagraph (G) of 
5        paragraph (1) of subsection (c) of Section 1-75 of 
6        this Act, and expected collections authorized under 
7        subparagraph (E) to determine whether and to what 
8        extent the limitations of subparagraph (E) would be 
9        exceeded by additional renewable energy credit 
10        procurement contract awards.
11                (aa) If the Agency determines that additional 
12            renewable energy credit procurement contract 
13            awards could be made without exceeding the 
14            limitations of subparagraph (E), then the 
15            procurements shall be authorized at a scale 
16            determined not to exceed the limitations of 
17            subparagraph (E) in a manner consistent with the 
18            priorities of this Section.
19                (bb) If the Agency determines that additional 
20            renewable energy credit procurement contract 
21            awards cannot be made without exceeding the 
22            limitations of subparagraph (E), then the Agency 
23            shall suspend any new contract awards for the 
24            procurement of renewable energy credits until a 
25            new rate impact determination is made under 
26            subparagraph (E).
 
 
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1                (cc) Agency determinations made under this 
2            item (iv) shall be detailed and comprehensive and, 
3            if not made through the Agency's Long-Term 
4            Renewable Resources Procurement Plan, shall be 
5            filed as a compliance filing in the most recent 
6            docketed proceeding approving the Agency's 
7            Long-Term Renewable Resources Procurement Plan.
8                (dd) With respect to the procurement of 
9            renewable energy credits authorized through 
10            programs administered under subsection (b) of 
11            Section 1-56 and subparagraphs (K) through (M) of 
12            paragraph (1) of subsection (k) of Section 1-75 of 
13            this Act, the award of contracts for the 
14            procurement of renewable energy credits shall be 
15            suspended or reduced only at the conclusion of the 
16            program year in which the notice provided for 
17            under item (iii) of this subparagraph (E-5) is 
18            made. 
19                (ee) The contract shall provide that, so long 
20            as at least one of: (i) the cost recovery 
21            mechanisms referenced in subsection (k) of Section 
22            16-108 and subsection (l) of Section 16-111.5 of 
23            the Public Utilities Act remains in full force 
24            without limitation or (ii) the utility is 
25            otherwise authorized and or entitled to full, 
26            prompt, and uninterrupted recovery of its costs 
 
 
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1            through any other mechanism, then such seller 
2            shall be entitled to full, prompt, and 
3            uninterrupted payment under the applicable 
4            contract notwithstanding the application of this 
5            subparagraph (E). 
6        (F) If the limitation on the amount of renewable 
7    energy resources procured in subparagraph (E) of this 
8    paragraph (1) prevents the Agency from meeting all of the 
9    goals in this subsection (c), the Agency's long-term plan 
10    shall prioritize compliance with the requirements of this 
11    subsection (c) regarding renewable energy credits in the 
12    following order:
13            (i) renewable energy credits under existing 
14        contractual obligations as of June 1, 2021;
15            (i-5) funding for the Illinois Solar for All 
16        Program, as described in subparagraph (O) of this 
17        paragraph (1); 
18            (ii) renewable energy credits necessary to comply 
19        with the new wind and new photovoltaic procurement 
20        requirements described in items (i) through (iii) of 
21        subparagraph (C) of this paragraph (1); and
22            (iii) renewable energy credits necessary to meet 
23        the remaining requirements of this subsection (c).
24        (G) The following provisions shall apply to the 
25    Agency's procurement of renewable energy credits under 
26    this subsection (c):
 
 
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1            (i) Notwithstanding whether a long-term renewable 
2        resources procurement plan has been approved, the 
3        Agency shall conduct an initial forward procurement 
4        for renewable energy credits from new utility-scale 
5        wind projects within 160 days after June 1, 2017 (the 
6        effective date of Public Act 99-906). For the purposes 
7        of this initial forward procurement, the Agency shall 
8        solicit 15-year contracts for delivery of 1,000,000 
9        renewable energy credits delivered annually from new 
10        utility-scale wind projects to begin delivery on June 
11        1, 2019, if available, but not later than June 1, 2021, 
12        unless the project has delays in the establishment of 
13        an operating interconnection with the applicable 
14        transmission or distribution system as a result of the 
15        actions or inactions of the transmission or 
16        distribution provider, or other causes for force 
17        majeure as outlined in the procurement contract, in 
18        which case, not later than June 1, 2022. Payments to 
19        suppliers of renewable energy credits shall commence 
20        upon delivery. Renewable energy credits procured under 
21        this initial procurement shall be included in the 
22        Agency's long-term plan and shall apply to all 
23        renewable energy goals in this subsection (c).
24            (ii) Notwithstanding whether a long-term renewable 
25        resources procurement plan has been approved, the 
26        Agency shall conduct an initial forward procurement 
 
 
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1        for renewable energy credits from new utility-scale 
2        solar projects and brownfield site photovoltaic 
3        projects within one year after June 1, 2017 (the 
4        effective date of Public Act 99-906). For the purposes 
5        of this initial forward procurement, the Agency shall 
6        solicit 15-year contracts for delivery of 1,000,000 
7        renewable energy credits delivered annually from new 
8        utility-scale solar projects and brownfield site 
9        photovoltaic projects to begin delivery on June 1, 
10        2019, if available, but not later than June 1, 2021, 
11        unless the project has delays in the establishment of 
12        an operating interconnection with the applicable 
13        transmission or distribution system as a result of the 
14        actions or inactions of the transmission or 
15        distribution provider, or other causes for force 
16        majeure as outlined in the procurement contract, in 
17        which case, not later than June 1, 2022. The Agency may 
18        structure this initial procurement in one or more 
19        discrete procurement events. Payments to suppliers of 
20        renewable energy credits shall commence upon delivery. 
21        Renewable energy credits procured under this initial 
22        procurement shall be included in the Agency's 
23        long-term plan and shall apply to all renewable energy 
24        goals in this subsection (c).
25            (iii) Notwithstanding whether the Commission has 
26        approved the periodic long-term renewable resources 
 
 
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1        procurement plan revision described in Section 
2        16-111.5 of the Public Utilities Act, the Agency shall 
3        conduct at least one subsequent forward procurement 
4        for renewable energy credits from new utility-scale 
5        wind projects, new utility-scale solar projects, and 
6        new brownfield site photovoltaic projects within 240 
7        days after the effective date of this amendatory Act 
8        of the 102nd General Assembly in quantities necessary 
9        to meet the requirements of subparagraph (C) of this 
10        paragraph (1) through the delivery year beginning June 
11        1, 2021.
12            (iv) Notwithstanding whether the Commission has 
13        approved the periodic long-term renewable resources 
14        procurement plan revision described in Section 
15        16-111.5 of the Public Utilities Act, the Agency shall 
16        open capacity for each category in the Adjustable 
17        Block program within 90 days after the effective date 
18        of this amendatory Act of the 102nd General Assembly 
19        manner:
20                (1) The Agency shall open the first block of 
21            annual capacity for the category described in item 
22            (i) of subparagraph (K) of this paragraph (1). The 
23            first block of annual capacity for item (i) shall 
24            be for at least 75 megawatts of total nameplate 
25            capacity. The price of the renewable energy credit 
26            for this block of capacity shall be 4% less than 
 
 
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1            the price of the last open block in this category. 
2            Projects on a waitlist shall be awarded contracts 
3            first in the order in which they appear on the 
4            waitlist. Notwithstanding anything to the 
5            contrary, for those renewable energy credits that 
6            qualify and are procured under this subitem (1) of 
7            this item (iv), the renewable energy credit 
8            delivery contract value shall be paid in full, 
9            based on the estimated generation during the first 
10            15 years of operation, by the contracting 
11            utilities at the time that the facility producing 
12            the renewable energy credits is interconnected at 
13            the distribution system level of the utility and 
14            verified as energized and in compliance by the 
15            Program Administrator. The electric utility shall 
16            receive and retire all renewable energy credits 
17            generated by the project for the first 15 years of 
18            operation. Renewable energy credits generated by 
19            the project thereafter shall not be transferred 
20            under the renewable energy credit delivery 
21            contract with the counterparty electric utility.
22                (2) The Agency shall open the first block of 
23            annual capacity for the category described in item 
24            (ii) of subparagraph (K) of this paragraph (1). 
25            The first block of annual capacity for item (ii) 
26            shall be for at least 75 megawatts of total 
 
 
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1            nameplate capacity.
2                    (A) The price of the renewable energy 
3                credit for any project on a waitlist for this 
4                category before the opening of this block 
5                shall be 4% less than the price of the last 
6                open block in this category. Projects on the 
7                waitlist shall be awarded contracts first in 
8                the order in which they appear on the 
9                waitlist. Any projects that are less than or 
10                equal to 25 kilowatts in size on the waitlist 
11                for this capacity shall be moved to the 
12                waitlist for paragraph (1) of this item (iv). 
13                Notwithstanding anything to the contrary, 
14                projects that were on the waitlist prior to 
15                opening of this block shall not be required to 
16                be in compliance with the requirements of 
17                subparagraph (Q) of this paragraph (1) of this 
18                subsection (c). Notwithstanding anything to 
19                the contrary, for those renewable energy 
20                credits procured from projects that were on 
21                the waitlist for this category before the 
22                opening of this block 20% of the renewable 
23                energy credit delivery contract value, based 
24                on the estimated generation during the first 
25                15 years of operation, shall be paid by the 
26                contracting utilities at the time that the 
 
 
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1                facility producing the renewable energy 
2                credits is interconnected at the distribution 
3                system level of the utility and verified as 
4                energized by the Program Administrator. The 
5                remaining portion shall be paid ratably over 
6                the subsequent 4-year period. The electric 
7                utility shall receive and retire all renewable 
8                energy credits generated by the project during 
9                the first 15 years of operation. Renewable 
10                energy credits generated by the project 
11                thereafter shall not be transferred under the 
12                renewable energy credit delivery contract with 
13                the counterparty electric utility.
14                    (B) The price of renewable energy credits 
15                for any project not on the waitlist for this 
16                category before the opening of the block shall 
17                be determined and published by the Agency. 
18                Projects not on a waitlist as of the opening 
19                of this block shall be subject to the 
20                requirements of subparagraph (Q) of this 
21                paragraph (1), as applicable. Projects not on 
22                a waitlist as of the opening of this block 
23                shall be subject to the contract provisions 
24                outlined in item (iii) of subparagraph (L) of 
25                this paragraph (1). The Agency shall strive to 
26                publish updated prices and an updated 
 
 
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1                renewable energy credit delivery contract as 
2                quickly as possible. 
3                (3) For opening the first 2 blocks of annual 
4            capacity for projects participating in item (iii) 
5            of subparagraph (K) of paragraph (1) of subsection 
6            (c), projects shall be selected exclusively from 
7            those projects on the ordinal waitlists of 
8            community renewable generation projects 
9            established by the Agency based on the status of 
10            those ordinal waitlists as of December 31, 2020, 
11            and only those projects previously determined to 
12            be eligible for the Agency's April 2019 community 
13            solar project selection process.
14                The first 2 blocks of annual capacity for item 
15            (iii) shall be for 250 megawatts of total 
16            nameplate capacity, with both blocks opening 
17            simultaneously under the schedule outlined in the 
18            paragraphs below. Projects shall be selected as 
19            follows:
20                    (A) The geographic balance of selected 
21                projects shall follow the Group classification 
22                found in the Agency's Revised Long-Term 
23                Renewable Resources Procurement Plan, with 70% 
24                of capacity allocated to projects on the Group 
25                B waitlist and 30% of capacity allocated to 
26                projects on the Group A waitlist.
 
 
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1                    (B) Contract awards for waitlisted 
2                projects shall be allocated proportionate to 
3                the total nameplate capacity amount across 
4                both ordinal waitlists associated with that 
5                applicant firm or its affiliates, subject to 
6                the following conditions.
7                        (i) Each applicant firm having a 
8                    waitlisted project eligible for selection 
9                    shall receive no less than 500 kilowatts 
10                    in awarded capacity across all groups, and 
11                    no approved vendor may receive more than 
12                    20% of each Group's waitlist allocation.
13                        (ii) Each applicant firm, upon 
14                    receiving an award of program capacity 
15                    proportionate to its waitlisted capacity, 
16                    may then determine which waitlisted 
17                    projects it chooses to be selected for a 
18                    contract award up to that capacity amount.
19                        (iii) Assuming all other program 
20                    requirements are met, applicant firms may 
21                    adjust the nameplate capacity of applicant 
22                    projects without losing waitlist 
23                    eligibility, so long as no project is 
24                    greater than 2,000 kilowatts in size.
25                        (iv) Assuming all other program 
26                    requirements are met, applicant firms may 
 
 
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1                    adjust the expected production associated 
2                    with applicant projects, subject to 
3                    verification by the Program Administrator.
4                    (C) After a review of affiliate 
5                information and the current ordinal waitlists, 
6                the Agency shall announce the nameplate 
7                capacity award amounts associated with 
8                applicant firms no later than 90 days after 
9                the effective date of this amendatory Act of 
10                the 102nd General Assembly.
11                    (D) Applicant firms shall submit their 
12                portfolio of projects used to satisfy those 
13                contract awards no less than 90 days after the 
14                Agency's announcement. The total nameplate 
15                capacity of all projects used to satisfy that 
16                portfolio shall be no greater than the 
17                Agency's nameplate capacity award amount 
18                associated with that applicant firm. An 
19                applicant firm may decline, in whole or in 
20                part, its nameplate capacity award without 
21                penalty, with such unmet capacity rolled over 
22                to the next block opening for project 
23                selection under item (iii) of subparagraph (K) 
24                of this subsection (c). Any projects not 
25                included in an applicant firm's portfolio may 
26                reapply without prejudice upon the next block 
 
 
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1                reopening for project selection under item 
2                (iii) of subparagraph (K) of this subsection 
3                (c).
4                    (E) The renewable energy credit delivery 
5                contract shall be subject to the contract and 
6                payment terms outlined in item (iv) of 
7                subparagraph (L) of this subsection (c). 
8                Contract instruments used for this 
9                subparagraph shall contain the following 
10                terms:
11                        (i) Renewable energy credit prices 
12                    shall be fixed, without further adjustment 
13                    under any other provision of this Act or 
14                    for any other reason, at 10% lower than 
15                    prices applicable to the last open block 
16                    for this category, inclusive of any adders 
17                    available for achieving a minimum of 50% 
18                    of subscribers to the project's nameplate 
19                    capacity being residential or small 
20                    commercial customers with subscriptions of 
21                    below 25 kilowatts in size;
22                        (ii) A requirement that a minimum of 
23                    50% of subscribers to the project's 
24                    nameplate capacity be residential or small 
25                    commercial customers with subscriptions of 
26                    below 25 kilowatts in size;
 
 
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1                        (iii) Permission for the ability of a 
2                    contract holder to substitute projects 
3                    with other waitlisted projects without 
4                    penalty should a project receive a 
5                    non-binding estimate of costs to construct 
6                    the interconnection facilities and any 
7                    required distribution upgrades associated 
8                    with that project of greater than 30 cents 
9                    per watt AC of that project's nameplate 
10                    capacity. In developing the applicable 
11                    contract instrument, the Agency may 
12                    consider whether other circumstances 
13                    outside of the control of the applicant 
14                    firm should also warrant project 
15                    substitution rights.
16                    The Agency shall publish a finalized 
17                updated renewable energy credit delivery 
18                contract developed consistent with these terms 
19                and conditions no less than 30 days before 
20                applicant firms must submit their portfolio of 
21                projects pursuant to item (D).
22                    (F) To be eligible for an award, the 
23                applicant firm shall certify that not less 
24                than prevailing wage, as determined pursuant 
25                to the Illinois Prevailing Wage Act, was or 
26                will be paid to employees who are engaged in 
 
 
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1                construction activities associated with a 
2                selected project.
3                (4) The Agency shall open the first block of 
4            annual capacity for the category described in item 
5            (iv) of subparagraph (K) of this paragraph (1). 
6            The first block of annual capacity for item (iv) 
7            shall be for at least 50 megawatts of total 
8            nameplate capacity. Renewable energy credit prices 
9            shall be fixed, without further adjustment under 
10            any other provision of this Act or for any other 
11            reason, at the price in the last open block in the 
12            category described in item (ii) of subparagraph 
13            (K) of this paragraph (1). Pricing for future 
14            blocks of annual capacity for this category may be 
15            adjusted in the Agency's second revision to its 
16            Long-Term Renewable Resources Procurement Plan. 
17            Projects in this category shall be subject to the 
18            contract terms outlined in item (iv) of 
19            subparagraph (L) of this paragraph (1).
20                (5) The Agency shall open the equivalent of 2 
21            years of annual capacity for the category 
22            described in item (v) of subparagraph (K) of this 
23            paragraph (1). The first block of annual capacity 
24            for item (v) shall be for at least 10 megawatts of 
25            total nameplate capacity. Notwithstanding the 
26            provisions of item (v) of subparagraph (K) of this 
 
 
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1            paragraph (1), for the purpose of this initial 
2            block, the agency shall accept new project 
3            applications intended to increase the diversity of 
4            areas hosting community solar projects, the 
5            business models of projects, and the size of 
6            projects, as described by the Agency in its 
7            long-term renewable resources procurement plan 
8            that is approved as of the effective date of this 
9            amendatory Act of the 102nd General Assembly. 
10            Projects in this category shall be subject to the 
11            contract terms outlined in item (iii) of 
12            subsection (L) of this paragraph (1).
13                (6) The Agency shall open the first blocks of 
14            annual capacity for the category described in item 
15            (vi) of subparagraph (K) of this paragraph (1), 
16            with allocations of capacity within the block 
17            generally matching the historical share of block 
18            capacity allocated between the category described 
19            in items (i) and (ii) of subparagraph (K) of this 
20            paragraph (1). The first two blocks of annual 
21            capacity for item (vi) shall be for at least 75 
22            megawatts of total nameplate capacity. The price 
23            of renewable energy credits for the blocks of 
24            capacity shall be 4% less than the price of the 
25            last open blocks in the categories described in 
26            items (i) and (ii) of subparagraph (K) of this 
 
 
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1            paragraph (1). Pricing for future blocks of annual 
2            capacity for this category may be adjusted in the 
3            Agency's second revision to its Long-Term 
4            Renewable Resources Procurement Plan. Projects in 
5            this category shall be subject to the applicable 
6            contract terms outlined in items (ii) and (iii) of 
7            subparagraph (L) of this paragraph (1).
8            (v) Upon the effective date of this amendatory Act 
9        of the 102nd General Assembly, for all competitive 
10        procurements and any procurements of renewable energy 
11        credit from new utility-scale wind and new 
12        utility-scale photovoltaic projects, the Agency shall 
13        procure indexed renewable energy credits and direct 
14        respondents to offer a strike price.
15                (1) The purchase price of the indexed 
16            renewable energy credit payment shall be 
17            calculated for each settlement period. That 
18            payment, for any settlement period, shall be equal 
19            to the difference resulting from subtracting the 
20            strike price from the index price for that 
21            settlement period. If this difference results in a 
22            negative number, the indexed REC counterparty 
23            shall owe the seller the absolute value multiplied 
24            by the quantity of energy produced in the relevant 
25            settlement period. If this difference results in a 
26            positive number, the seller shall owe the indexed 
 
 
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1            REC counterparty this amount multiplied by the 
2            quantity of energy produced in the relevant 
3            settlement period.
4                (2) Parties shall cash settle every month, 
5            summing up all settlements (both positive and 
6            negative, if applicable) for the prior month.
7                (3) To ensure funding in the annual budget 
8            established under subparagraph (E) for indexed 
9            renewable energy credit procurements for each year 
10            of the term of such contracts, which must have a 
11            minimum tenure of 20 calendar years, the 
12            procurement administrator, Agency, Commission 
13            staff, and procurement monitor shall quantify the 
14            annual cost of the contract by utilizing one or 
15            more an industry-standard, third-party forward 
16            price curves curve for energy at the appropriate 
17            hub or load zone, including the estimated 
18            magnitude and timing of the price effects related 
19            to federal carbon controls. Each forward price 
20            curve shall contain a specific value of the 
21            forecasted market price of electricity for each 
22            annual delivery year of the contract. For 
23            procurement planning purposes, the impact on the 
24            annual budget for the cost of indexed renewable 
25            energy credits for each delivery year shall be 
26            determined as the expected annual contract 
 
 
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1            expenditure for that year, equaling the difference 
2            between (i) the sum across all relevant contracts 
3            of the applicable strike price multiplied by 
4            contract quantity and (ii) the sum across all 
5            relevant contracts of the forward price curve for 
6            the applicable load zone for that year multiplied 
7            by contract quantity. The contracting utility 
8            shall not assume an obligation in excess of the 
9            estimated annual cost of the contracts for indexed 
10            renewable energy credits. Forward curves shall be 
11            revised on an annual basis as updated forward 
12            price curves are released and filed with the 
13            Commission in the proceeding approving the 
14            Agency's most recent long-term renewable resources 
15            procurement plan. If the expected contract spend 
16            is higher or lower than the total quantity of 
17            contracts multiplied by the forward price curve 
18            value for that year, the forward price curve shall 
19            be updated by the procurement administrator, in 
20            consultation with the Agency, Commission staff, 
21            and procurement monitors, using then-currently 
22            available price forecast data and additional 
23            budget dollars shall be obligated or reobligated 
24            as appropriate.
25                (4) To ensure that indexed renewable energy 
26            credit prices remain predictable and affordable, 
 
 
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1            the Agency may consider the institution of a price 
2            collar on REC prices paid under indexed renewable 
3            energy credit procurements establishing floor and 
4            ceiling REC prices applicable to indexed REC 
5            contract prices. Any price collars applicable to 
6            indexed REC procurements shall be proposed by the 
7            Agency through its long-term renewable resources 
8            procurement plan. 
9            (vi) All procurements under this subparagraph (G), 
10        including the procurement of renewable energy credits 
11        from hydropower facilities, shall comply with the 
12        geographic requirements in subparagraph (I) of this 
13        paragraph (1) and shall follow the procurement 
14        processes and procedures described in this Section and 
15        Section 16-111.5 of the Public Utilities Act to the 
16        extent practicable, and these processes and procedures 
17        may be expedited to accommodate the schedule 
18        established by this subparagraph (G). To ensure the 
19        successful development of new renewable energy 
20        projects supported through competitive procurements, 
21        for any procurements conducted under items (i), (ii), 
22        (iii), and (v) of this subparagraph (G) and any other 
23        procurement of new utility-scale wind or utility-scale 
24        solar projects that were entered into prior to January 
25        1, 2025, the Agency shall allow, upon a demonstration 
26        of need to ensure the commercial viability of a 
 
 
10400SB0025ham004- 235 -LRB104 16098 AAS 29398 a

1        project, for a one-time, post-award renegotiation of 
2        select contract terms prior to the project's 
3        commercial operation date through bilateral 
4        negotiation between the Agency, the buyer, and a 
5        winning bidder. Contract terms subject to 
6        renegotiation may include the project map, as defined 
7        under the applicable competitive solicitation, the 
8        real estate footprint or any limitations thereof, the 
9        location of the generators, or a potential reduction 
10        in the quantity of renewable energy credits to be 
11        delivered. Provisions related to a renewable energy 
12        credit delivery shortfall and the event of default may 
13        be replaced with similar provisions approved by the 
14        Agency in subsequent years or subsequent to a 
15        successful bid. Post-award renegotiation of 
16        competitively bid renewable energy credit contracts 
17        entered into prior to January 1, 2025 shall not be 
18        permitted to the extent such renegotiation would 
19        result in (1) the point of interconnection being 
20        within the service area of a different state, a 
21        different regional transmission organization zone, or 
22        a different regional transmission organization, (2) 
23        the generator no longer meeting the definition of the 
24        resource category for which the winning bidder was 
25        originally awarded a contract, (3) the generator no 
26        longer meeting the Agency's public interest criteria 
 
 
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1        as established in the long-term renewable resources 
2        plan in effect at the time of the contract award, or 
3        (4) a change to material terms of the renewable energy 
4        credit contract unrelated to project land or footprint 
5        or the number of renewable energy credits to be 
6        delivered, including the applicable bid price or 
7        strike price. If the Agency, the buyer, and the 
8        winning bidder reach an agreement on amended terms, 
9        then, upon petition by the winning bidder or current 
10        seller, the Commission shall issue an order directing 
11        the utility counterparty to execute an amendment 
12        drafted by the Agency with the revised terms to the 
13        renewable energy credit contract, the product order, 
14        or both. The Agency shall provide the amendment to the 
15        utility within 15 business days after the Commission's 
16        order, and the utility shall execute the amendment no 
17        more than 7 calendar days after delivery by the 
18        Agency.    
19            (vii) On and after the effective date of this 
20        amendatory Act of the 103rd General Assembly, for all 
21        procurements of renewable energy credits from 
22        hydropower facilities, the Agency shall establish 
23        contract terms designed to optimize existing 
24        hydropower facilities through modernization or 
25        retooling and establish new hydropower facilities at 
26        existing dams. Procurements made under this item (vii) 
 
 
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1        shall prioritize projects located in designated 
2        environmental justice communities, as defined in 
3        subsection (b) of Section 1-56 of this Act, or in 
4        projects located in units of local government with 
5        median incomes that do not exceed 82% of the median 
6        income of the State. 
7        (H) The procurement of renewable energy resources for 
8    a given delivery year shall be reduced as described in 
9    this subparagraph (H) if an alternative retail electric 
10    supplier meets the requirements described in this 
11    subparagraph (H). 
12            (i) Within 45 days after June 1, 2017 (the 
13        effective date of Public Act 99-906), an alternative 
14        retail electric supplier or its successor shall submit 
15        an informational filing to the Illinois Commerce 
16        Commission certifying that, as of December 31, 2015, 
17        the alternative retail electric supplier owned one or 
18        more electric generating facilities that generates 
19        renewable energy resources as defined in Section 1-10 
20        of this Act, provided that such facilities are not 
21        powered by wind or photovoltaics, and the facilities 
22        generate one renewable energy credit for each 
23        megawatthour of energy produced from the facility.
24            The informational filing shall identify each 
25        facility that was eligible to satisfy the alternative 
26        retail electric supplier's obligations under Section 
 
 
10400SB0025ham004- 238 -LRB104 16098 AAS 29398 a

1        16-115D of the Public Utilities Act as described in 
2        this item (i).
3            (ii) For a given delivery year, the alternative 
4        retail electric supplier may elect to supply its 
5        retail customers with renewable energy credits from 
6        the facility or facilities described in item (i) of 
7        this subparagraph (H) that continue to be owned by the 
8        alternative retail electric supplier.
9            (iii) The alternative retail electric supplier 
10        shall notify the Agency and the applicable utility, no 
11        later than February 28 of the year preceding the 
12        applicable delivery year or 15 days after June 1, 2017 
13        (the effective date of Public Act 99-906), whichever 
14        is later, of its election under item (ii) of this 
15        subparagraph (H) to supply renewable energy credits to 
16        retail customers of the utility. Such election shall 
17        identify the amount of renewable energy credits to be 
18        supplied by the alternative retail electric supplier 
19        to the utility's retail customers and the source of 
20        the renewable energy credits identified in the 
21        informational filing as described in item (i) of this 
22        subparagraph (H), subject to the following 
23        limitations:
24                For the delivery year beginning June 1, 2018, 
25            the maximum amount of renewable energy credits to 
26            be supplied by an alternative retail electric 
 
 
10400SB0025ham004- 239 -LRB104 16098 AAS 29398 a

1            supplier under this subparagraph (H) shall be 68% 
2            multiplied by 25% multiplied by 14.5% multiplied 
3            by the amount of metered electricity 
4            (megawatt-hours) delivered by the alternative 
5            retail electric supplier to Illinois retail 
6            customers during the delivery year ending May 31, 
7            2016.
8                For delivery years beginning June 1, 2019 and 
9            each year thereafter, the maximum amount of 
10            renewable energy credits to be supplied by an 
11            alternative retail electric supplier under this 
12            subparagraph (H) shall be 68% multiplied by 50% 
13            multiplied by 16% multiplied by the amount of 
14            metered electricity (megawatt-hours) delivered by 
15            the alternative retail electric supplier to 
16            Illinois retail customers during the delivery year 
17            ending May 31, 2016, provided that the 16% value 
18            shall increase by 1.5% each delivery year 
19            thereafter to 25% by the delivery year beginning 
20            June 1, 2025, and thereafter the 25% value shall 
21            apply to each delivery year.
22            For each delivery year, the total amount of 
23        renewable energy credits supplied by all alternative 
24        retail electric suppliers under this subparagraph (H) 
25        shall not exceed 9% of the Illinois target renewable 
26        energy credit quantity. The Illinois target renewable 
 
 
10400SB0025ham004- 240 -LRB104 16098 AAS 29398 a

1        energy credit quantity for the delivery year beginning 
2        June 1, 2018 is 14.5% multiplied by the total amount of 
3        metered electricity (megawatt-hours) delivered in the 
4        delivery year immediately preceding that delivery 
5        year, provided that the 14.5% shall increase by 1.5% 
6        each delivery year thereafter to 25% by the delivery 
7        year beginning June 1, 2025, and thereafter the 25% 
8        value shall apply to each delivery year.
9            If the requirements set forth in items (i) through 
10        (iii) of this subparagraph (H) are met, the charges 
11        that would otherwise be applicable to the retail 
12        customers of the alternative retail electric supplier 
13        under paragraph (6) of this subsection (c) for the 
14        applicable delivery year shall be reduced by the ratio 
15        of the quantity of renewable energy credits supplied 
16        by the alternative retail electric supplier compared 
17        to that supplier's target renewable energy credit 
18        quantity. The supplier's target renewable energy 
19        credit quantity for the delivery year beginning June 
20        1, 2018 is 14.5% multiplied by the total amount of 
21        metered electricity (megawatt-hours) delivered by the 
22        alternative retail supplier in that delivery year, 
23        provided that the 14.5% shall increase by 1.5% each 
24        delivery year thereafter to 25% by the delivery year 
25        beginning June 1, 2025, and thereafter the 25% value 
26        shall apply to each delivery year. 
 
 
10400SB0025ham004- 241 -LRB104 16098 AAS 29398 a

1            On or before April 1 of each year, the Agency shall 
2        annually publish a report on its website that 
3        identifies the aggregate amount of renewable energy 
4        credits supplied by alternative retail electric 
5        suppliers under this subparagraph (H). 
6        (I) The Agency shall design its long-term renewable 
7    energy procurement plan to maximize the State's interest 
8    in the health, safety, and welfare of its residents, 
9    including but not limited to minimizing sulfur dioxide, 
10    nitrogen oxide, particulate matter and other pollution 
11    that adversely affects public health in this State, 
12    increasing fuel and resource diversity in this State, 
13    enhancing the reliability and resiliency of the 
14    electricity distribution system in this State, meeting 
15    goals to limit carbon dioxide emissions under federal or 
16    State law, and contributing to a cleaner and healthier 
17    environment for the citizens of this State. In order to 
18    further these legislative purposes, renewable energy 
19    credits shall be eligible to be counted toward the 
20    renewable energy requirements of this subsection (c) if 
21    they are generated from facilities located in this State. 
22    The Agency may qualify renewable energy credits from 
23    facilities located in states adjacent to Illinois or 
24    renewable energy credits associated with the electricity 
25    generated by a utility-scale wind energy facility or 
26    utility-scale photovoltaic facility and transmitted by a 
 
 
10400SB0025ham004- 242 -LRB104 16098 AAS 29398 a

1    qualifying direct current project described in subsection 
2    (b-5) of Section 8-406 of the Public Utilities Act to a 
3    delivery point on the electric transmission grid located 
4    in this State or a state adjacent to Illinois, if the 
5    generator demonstrates and the Agency determines that the 
6    operation of such facility or facilities will help promote 
7    the State's interest in the health, safety, and welfare of 
8    its residents based on the public interest criteria 
9    described above. For the purposes of this Section, 
10    renewable resources that are delivered via a high voltage 
11    direct current converter station located in Illinois shall 
12    be deemed generated in Illinois at the time and location 
13    the energy is converted to alternating current by the high 
14    voltage direct current converter station if the high 
15    voltage direct current transmission line: (i) after the 
16    effective date of this amendatory Act of the 102nd General 
17    Assembly, was constructed with a project labor agreement; 
18    (ii) is capable of transmitting electricity at 525kv; 
19    (iii) has an Illinois converter station located and 
20    interconnected in the region of the PJM Interconnection, 
21    LLC; (iv) does not operate as a public utility; and (v) if 
22    the high voltage direct current transmission line was 
23    energized after June 1, 2023. To ensure that the public 
24    interest criteria are applied to the procurement and given 
25    full effect, the Agency's long-term procurement plan shall 
26    describe in detail how each public interest factor shall 
 
 
10400SB0025ham004- 243 -LRB104 16098 AAS 29398 a

1    be considered and weighted for facilities located in 
2    states adjacent to Illinois.
3        (J) In order to promote the competitive development of 
4    renewable energy resources in furtherance of the State's 
5    interest in the health, safety, and welfare of its 
6    residents, renewable energy credits shall not be eligible 
7    to be counted toward the renewable energy requirements of 
8    this subsection (c) if they are sourced from a generating 
9    unit whose costs were being recovered through rates 
10    regulated by this State or any other state or states on or 
11    after January 1, 2017. Each contract executed to purchase 
12    renewable energy credits under this subsection (c) shall 
13    provide for the contract's termination if the costs of the 
14    generating unit supplying the renewable energy credits 
15    subsequently begin to be recovered through rates regulated 
16    by this State or any other state or states; and each 
17    contract shall further provide that, in that event, the 
18    supplier of the credits must return 110% of all payments 
19    received under the contract. Amounts returned under the 
20    requirements of this subparagraph (J) shall be retained by 
21    the utility and all of these amounts shall be used for the 
22    procurement of additional renewable energy credits from 
23    new wind or new photovoltaic resources as defined in this 
24    subsection (c). The long-term plan shall provide that 
25    these renewable energy credits shall be procured in the 
26    next procurement event.
 
 
10400SB0025ham004- 244 -LRB104 16098 AAS 29398 a

1        Notwithstanding the limitations of this subparagraph 
2    (J), renewable energy credits sourced from generating 
3    units that are constructed, purchased, owned, or leased by 
4    an electric utility as part of an approved project, 
5    program, or pilot under Section 1-56 of this Act shall be 
6    eligible to be counted toward the renewable energy 
7    requirements of this subsection (c), regardless of how the 
8    costs of these units are recovered. As long as a 
9    generating unit or an identifiable portion of a generating 
10    unit has not had and does not have its costs recovered 
11    through rates regulated by this State or any other state, 
12    HVDC renewable energy credits associated with that 
13    generating unit or identifiable portion thereof shall be 
14    eligible to be counted toward the renewable energy 
15    requirements of this subsection (c). 
16        (K) The long-term renewable resources procurement plan 
17    developed by the Agency in accordance with subparagraph 
18    (A) of this paragraph (1) shall include an Adjustable 
19    Block program for the procurement of renewable energy 
20    credits from new photovoltaic projects that are 
21    distributed renewable energy generation devices or new 
22    photovoltaic community renewable generation projects. The 
23    Adjustable Block program shall be generally designed to 
24    provide for the steady, predictable, and sustainable 
25    growth of new solar photovoltaic development in Illinois. 
26    To this end, the Adjustable Block program shall provide a 
 
 
10400SB0025ham004- 245 -LRB104 16098 AAS 29398 a

1    transparent annual schedule of prices and quantities to 
2    enable the photovoltaic market to scale up and for 
3    renewable energy credit prices to adjust at a predictable 
4    rate over time. The prices set by the Adjustable Block 
5    program can be reflected as a set value or as the product 
6    of a formula.
7        The Adjustable Block program shall include for each 
8    category of eligible projects for each delivery year: a 
9    single block of nameplate capacity, a price for renewable 
10    energy credits within that block, and the terms and 
11    conditions for securing a spot on a waitlist once the 
12    block is fully committed or reserved. Except as outlined 
13    below, the waitlist of projects in a given year will carry 
14    over to apply to the subsequent year when another block is 
15    opened. Only projects energized on or after June 1, 2017 
16    shall be eligible for the Adjustable Block program. For 
17    each category for each delivery year the Agency shall 
18    determine the amount of generation capacity in each block, 
19    and the purchase price for each block, provided that the 
20    purchase price provided and the total amount of generation 
21    in all blocks for all categories shall be sufficient to 
22    meet the goals in this subsection (c). The Agency shall 
23    strive to issue a single block sized to provide for 
24    stability and market growth. The Agency shall establish 
25    program eligibility requirements that ensure that projects 
26    that enter the program are sufficiently mature to indicate 
 
 
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1    a demonstrable path to completion. The Agency may 
2    periodically review its prior decisions establishing the 
3    amount of generation capacity in each block, and the 
4    purchase price for each block, and may propose, on an 
5    expedited basis, changes to these previously set values, 
6    including but not limited to redistributing these amounts 
7    and the available funds as necessary and appropriate, 
8    subject to Commission approval as part of the periodic 
9    plan revision process described in Section 16-111.5 of the 
10    Public Utilities Act. The Agency may define different 
11    block sizes, purchase prices, or other distinct terms and 
12    conditions for projects located in different utility 
13    service territories if the Agency deems it necessary to 
14    meet the goals in this subsection (c).
15        The Adjustable Block program shall include the 
16    following categories in at least the following amounts:
17            (i) At least 20% from distributed renewable energy 
18        generation devices with a nameplate capacity of no 
19        more than 25 kilowatts.
20            (ii) At least 20% from distributed renewable 
21        energy generation devices with a nameplate capacity of 
22        more than 25 kilowatts and no more than 5,000 
23        kilowatts. The Agency may create sub-categories within 
24        this category to account for the differences between 
25        projects for small commercial customers, large 
26        commercial customers, and public or non-profit 
 
 
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1        customers. A project shall not be colocated with one 
2        or more other distributed renewable energy generation 
3        projects if the aggregate nameplate capacity of the 
4        projects exceeds 5,000 kilowatts AC. Notwithstanding 
5        any other provision of this Section, if 2 or more 
6        projects are developed, owned, or controlled by or 
7        originate from the same developer or an affiliated 
8        developer and the projects serve affiliated loads, the 
9        projects shall be colocated if the projects are 
10        located on adjacent parcels. If 2 or more projects are 
11        developed, owned, or controlled by or originate from 
12        the same developer and the projects serve unaffiliated 
13        loads, the projects may be colocated if documentation 
14        indicates affiliated management and ownership in the 
15        pre-development, development, construction, and 
16        management of the projects and the projects are 
17        located on a single or adjacent parcels. 
18        Notwithstanding any subsequent transfer, assignment, 
19        or conveyance of ownership or development rights to 
20        separate legal entities, the Agency shall consider, in 
21        its determination of whether projects are affiliated, 
22        evidence that the projects were pre-developed by the 
23        same legal entity or an affiliated entity. If the 
24        Agency determines the projects are affiliated, the 
25        projects shall be treated as colocated for purposes of 
26        aggregate nameplate capacity limitations and renewable 
 
 
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1        energy credit pricing adjustments. The Agency shall 
2        make exceptions on a case-by-case basis if it is 
3        demonstrated that projects on one parcel or projects 
4        on adjacent parcels are unaffiliated. For purposes of 
5        determining colocation, an approved vendor who submits 
6        an application for a distributed renewable energy 
7        generation project shall be required to submit an 
8        affidavit attesting that the project is not affiliated 
9        with any other distributed renewable energy generation 
10        project such that, if the 2 projects were deemed 
11        colocated, the projects would exceed the 5,000 
12        kilowatts nameplate capacity limitation. The receipt 
13        of an affidavit shall not restrict the Agency's 
14        ability to investigate and determine whether the 
15        project is, in fact, colocated.
16            For purposes of this item (ii):
17            "Affiliate" has the meaning given to that term in 
18        subitem (3) of item (iii) of this subparagraph (K).
19            "Colocated" means 2 or more distributed renewable 
20        energy generation projects that are located on a 
21        single parcel, except for projects where the owner of 
22        the applicable retail electric account is confirmed to 
23        be unaffiliated and the projects serve distinct 
24        electrical loads.
25            "Control" has the meaning given to that term in 
26        subitem (3) of item (iii) of this subparagraph (K).
 
 
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1            (iii) At least 30% from photovoltaic community 
2        renewable generation projects. Capacity for this 
3        category for the first 2 delivery years after the 
4        effective date of this amendatory Act of the 102nd 
5        General Assembly shall be allocated to waitlist 
6        projects as provided in paragraph (3) of item (iv) of 
7        subparagraph (G). Starting in the third delivery year 
8        after the effective date of this amendatory Act of the 
9        102nd General Assembly or earlier if the Agency 
10        determines there is additional capacity needed for to 
11        meet previous delivery year requirements, the 
12        following shall apply:
13                (1) the Agency shall select projects on a 
14            first-come, first-serve basis, however the Agency 
15            may suggest additional methods to prioritize 
16            projects that are submitted at the same time;
17                (2) projects shall have subscriptions of 25 kW 
18            or less for at least 50% of the facility's 
19            nameplate capacity and the Agency shall price the 
20            renewable energy credits with that as a factor;
21                (3) projects shall not be colocated with one 
22            or more other photovoltaic community renewable 
23            generation projects such that the aggregate 
24            nameplate capacity exceeds 10,000 kilowatts. The 
25            total nameplate capacity of colocated projects 
26            shall be the sum of the nameplate capacities of 
 
 
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1            the individual projects. For purposes of this 
2            subitem (3), separate legal formation of approved 
3            vendors, owners, or developers shall not preclude 
4            a finding of affiliation by the Agency. Evidence 
5            of affiliation may include, but is not limited to, 
6            shared personnel, common contractual or financing 
7            arrangements, a shared interconnection agreement, 
8            distinct interconnection agreements obtained by 
9            the same pre-development entity that are 
10            subsequently sold to distinct legal entities, 
11            familial relationships, or any demonstrable 
12            pattern of coordinated action in the 
13            pre-development, development, construction, or 
14            management of photovoltaic community renewable 
15            generation projects.
16                The Agency shall determine affiliation based 
17            on evidence that projects either (i) share a 
18            common origin on a parcel that has been subdivided 
19            in the 5 years before the date of application or 
20            (ii) were pre-developed before the beginning of 
21            construction by the same legal entity or an 
22            affiliated legal entity. The determination shall 
23            be made notwithstanding any subsequent transfer, 
24            assignment, or conveyance of ownership or 
25            development rights to separate legal entities. If 
26            the Agency determines the projects are affiliated, 
 
 
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1            the projects shall be treated as colocated for the 
2            purposes of aggregate nameplate capacity 
3            limitations and renewable energy credit pricing 
4            adjustments. The Agency shall make exceptions to 
5            this subitem (3) on a case-by-case basis if it is 
6            demonstrated that projects on one parcel or 
7            projects on adjacent parcels are unaffiliated.
8                A parcel shall not be divided into multiple 
9            parcels within the 5 years before the submission 
10            of a project application. If a parcel is divided 
11            within the preceding 5 years, a colocation 
12            determination shall be made based on the 
13            boundaries of the previous undivided parcel.
14                For purposes of determining colocation, an 
15            approved vendor who submits an application for a 
16            community renewable generation project shall be 
17            required to submit an affidavit attesting that (i) 
18            the parcel on which the project is sited has not 
19            been subdivided within the 5 years preceding the 
20            project application and (ii) the project is not 
21            affiliated with any other community renewable 
22            energy project in a manner that would cause the 2 
23            projects, if deemed colocated, to exceed the 
24            10,000 kilowatt nameplate capacity limitation. The 
25            receipt of an affidavit shall not restrict the 
26            Agency's ability to investigate and determine 
 
 
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1            whether the project is colocated.
2                Multiple community solar projects sited on 
3            distinct structures located on a single parcel 
4            shall be considered colocated and must demonstrate 
5            that the projects are unaffiliated in order to not 
6            be considered colocated. Each colocated project 
7            shall receive the renewable energy credit price 
8            corresponding to the total, aggregated nameplate 
9            capacity of the colocated systems, as determined 
10            at the time the second project's application is 
11            submitted to the Agency. If the second colocated 
12            project has been constructed and placed in service 
13            prior to application, and was placed in service 
14            more than 2 years after Commission approval of the 
15            original project, the colocation pricing 
16            adjustment shall not apply, and each project shall 
17            receive the standalone renewable energy credit 
18            price for its individual capacity.    
19                For purposes of this subitem (3):
20                "Affiliate" means any other entity that, 
21            directly or indirectly through one or more 
22            intermediaries, is controlled by or is under 
23            common control of the primary entity or a third 
24            entity. "Affiliate" includes family members for 
25            the purposes of colocation between projects. 
26            "Affiliate" does not include entities that have 
 
 
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1            shared sales or revenue-sharing arrangements or 
2            common debt and equity financing arrangements.
3                "Colocated" means 2 or more photovoltaic 
4            community renewable generation projects located on 
5            a single parcel or adjacent parcels, unless it is 
6            demonstrated that the projects are developed by 
7            unaffiliated entities.
8                "Control" means the possession, directly or 
9            indirectly, of the power to direct the management 
10            and policies of an entity , as defined in the 
11            Agency's first revised long-term renewable 
12            resources procurement plan approved by the 
13            Commission on February 18, 2020, such that the 
14            aggregate nameplate capacity exceeds 5,000 
15            kilowatts; and
16                (4) projects greater than 2 MW may not apply 
17            until after the approval of the Agency's revised 
18            Long-Term Renewable Resources Procurement Plan 
19            after the effective date of this amendatory Act of 
20            the 102nd General Assembly. 
21            (iv) At least 15% from distributed renewable 
22        generation devices or photovoltaic community renewable 
23        generation projects installed on public school land. 
24        The Agency may create subcategories within this 
25        category to account for the differences between 
26        project size or location. Projects located within 
 
 
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1        environmental justice communities or within 
2        Organizational Units that fall within Tier 1 or Tier 2 
3        shall be given priority. Each of the Agency's periodic 
4        updates to its long-term renewable resources 
5        procurement plan to incorporate the procurement 
6        described in this subparagraph (iv) shall also include 
7        the proposed quantities or blocks, pricing, and 
8        contract terms applicable to the procurement as 
9        indicated herein. In each such update and procurement, 
10        the Agency shall set the renewable energy credit price 
11        and establish payment terms for the renewable energy 
12        credits procured pursuant to this subparagraph (iv) 
13        that make it feasible and affordable for public 
14        schools to install photovoltaic distributed renewable 
15        energy devices on their premises, including, but not 
16        limited to, those public schools subject to the 
17        prioritization provisions of this subparagraph. For 
18        the purposes of this item (iv):
19            "Environmental Justice Community" shall have the 
20        same meaning set forth in the Agency's long-term 
21        renewable resources procurement plan;
22            "Organization Unit", "Tier 1" and "Tier 2" shall 
23        have the meanings set for in Section 18-8.15 of the 
24        School Code;
25            "Public schools" shall have the meaning set forth 
26        in Section 1-3 of the School Code and includes public 
 
 
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1        institutions of higher education, as defined in the 
2        Board of Higher Education Act.
3            (v) At least 5% from community-driven community 
4        solar projects intended to provide more direct and 
5        tangible connection and benefits to the communities 
6        which they serve or in which they operate and, 
7        additionally, to increase the variety of community 
8        solar locations, models, and options in Illinois. As 
9        part of its long-term renewable resources procurement 
10        plan, the Agency shall develop selection criteria for 
11        projects participating in this category. Nothing in 
12        this Section shall preclude the Agency from creating a 
13        selection process that maximizes community ownership 
14        and community benefits in selecting projects to 
15        receive renewable energy credits. Selection criteria 
16        shall include:
17                (1) community ownership or community 
18            wealth-building;
19                (2) additional direct and indirect community 
20            benefit, beyond project participation as a 
21            subscriber, including, but not limited to, 
22            economic, environmental, social, cultural, and 
23            physical benefits;
24                (3) meaningful involvement in project 
25            organization and development by community members 
26            or nonprofit organizations or public entities 
 
 
10400SB0025ham004- 256 -LRB104 16098 AAS 29398 a

1            located in or serving the community;
2                (4) engagement in project operations and 
3            management by nonprofit organizations, public 
4            entities, or community members; and
5                (5) whether a project is developed in response 
6            to a site-specific RFP developed by community 
7            members or a nonprofit organization or public 
8            entity located in or serving the community.
9            Selection criteria may also prioritize projects 
10        that:
11                (1) are developed in collaboration with or to 
12            provide complementary opportunities for the Clean 
13            Jobs Workforce Network Program, the Illinois 
14            Climate Works Preapprenticeship Program, the 
15            Returning Residents Clean Jobs Training Program, 
16            the Clean Energy Contractor Incubator Program, or 
17            the Clean Energy Primes Contractor Accelerator 
18            Program;
19                (2) increase the diversity of locations of 
20            community solar projects in Illinois, including by 
21            locating in urban areas and population centers;
22                (3) are located in Equity Investment Eligible 
23            Communities;
24                (4) are not greenfield projects;
25                (5) serve only local subscribers;
26                (6) have a nameplate capacity that does not 
 
 
10400SB0025ham004- 257 -LRB104 16098 AAS 29398 a

1            exceed 500 kW;
2                (7) are developed by an equity eligible 
3            contractor; or
4                (8) otherwise meaningfully advance the goals 
5            of providing more direct and tangible connection 
6            and benefits to the communities which they serve 
7            or in which they operate and increasing the 
8            variety of community solar locations, models, and 
9            options in Illinois.
10            For the purposes of this item (v):
11            "Community" means a social unit in which people 
12        come together regularly to effect change; a social 
13        unit in which participants are marked by a cooperative 
14        spirit, a common purpose, or shared interests or 
15        characteristics; or a space understood by its 
16        residents to be delineated through geographic 
17        boundaries or landmarks.
18            "Community benefit" means a range of services and 
19        activities that provide affirmative, economic, 
20        environmental, social, cultural, or physical value to 
21        a community; or a mechanism that enables economic 
22        development, high-quality employment, and education 
23        opportunities for local workers and residents, or 
24        formal monitoring and oversight structures such that 
25        community members may ensure that those services and 
26        activities respond to local knowledge and needs.
 
 
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1            "Community ownership" means an arrangement in 
2        which an electric generating facility is, or over time 
3        will be, in significant part, owned collectively by 
4        members of the community to which an electric 
5        generating facility provides benefits; members of that 
6        community participate in decisions regarding the 
7        governance, operation, maintenance, and upgrades of 
8        and to that facility; and members of that community 
9        benefit from regular use of that facility.
10            Terms and guidance within these criteria that are 
11        not defined in this item (v) shall be defined by the 
12        Agency, with stakeholder input, during the development 
13        of the Agency's long-term renewable resources 
14        procurement plan. The Agency shall develop regular 
15        opportunities for projects to submit applications for 
16        projects under this category, and develop selection 
17        criteria that gives preference to projects that better 
18        meet individual criteria as well as projects that 
19        address a higher number of criteria.
20            (vi) At least 10% from distributed renewable 
21        energy generation devices, which includes distributed 
22        renewable energy devices with a nameplate capacity 
23        under 5,000 kilowatts or photovoltaic community 
24        renewable generation projects, from applicants that 
25        are equity eligible contractors. The Agency may create 
26        subcategories within this category to account for the 
 
 
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1        differences between project size and type. The Agency 
2        shall propose to increase the percentage in this item 
3        (vi) over time to 40% based on factors, including, but 
4        not limited to, the number of equity eligible 
5        contractors and capacity used in this item (vi) in 
6        previous delivery years.
7            The Agency shall propose a payment structure for 
8        contracts executed pursuant to this paragraph under 
9        which, upon a demonstration of qualification or need 
10        under criteria established by the Agency that is 
11        focused on supporting small and emerging businesses 
12        and businesses that most acutely face barriers to the 
13        access of capital, applicant firms are advanced 
14        capital disbursed after contract execution but before 
15        the contracted project's energization. The amount or 
16        percentage of capital advanced prior to project 
17        energization shall be sufficient to both cover any 
18        increase in development costs resulting from 
19        prevailing wage requirements or project-labor 
20        agreements, and designed to overcome barriers in 
21        access to capital faced by equity eligible 
22        contractors. The amount or percentage of advanced 
23        capital may vary by subcategory within this category 
24        and by an applicant's demonstration of need, with such 
25        levels to be established through the Long-Term 
26        Renewable Resources Procurement Plan authorized under 
 
 
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1        subparagraph (A) of paragraph (1) of subsection (c) of 
2        this Section and any application requirements or 
3        evaluation criteria developed pursuant to the Plan.
4            Contracts developed featuring capital advanced 
5        prior to a project's energization shall feature 
6        provisions to ensure both the successful development 
7        of applicant projects and the delivery of the 
8        renewable energy credits for the full term of the 
9        contract, including ongoing collateral requirements 
10        and other provisions deemed necessary by the Agency, 
11        and may include energization timelines longer than for 
12        comparable project types. The percentage or amount of 
13        capital advanced prior to project energization shall 
14        not operate to increase the overall contract value, 
15        however contracts executed under this subparagraph may 
16        feature renewable energy credit prices higher than 
17        those offered to similar projects participating in 
18        other categories. Capital advanced prior to 
19        energization shall serve to reduce the ratable 
20        payments made after energization under items (ii) and 
21        (iii) of subparagraph (L) or payments made for each 
22        renewable energy credit delivery under item (iv) of 
23        subparagraph (L).
24            For projects developed under this item (vi), the 
25        Agency shall take steps to encourage higher portions 
26        of contract value to be provided to equity eligible 
 
 
10400SB0025ham004- 261 -LRB104 16098 AAS 29398 a

1        contractors and to support equity eligible persons who 
2        participate in this Program and who exercise control 
3        and actively manage their businesses and their 
4        businesses' contractual projects. These steps may 
5        include, but are not limited to, differentiated REC 
6        prices, exceptions or exemptions, and other mechanisms 
7        and requirements for nonnominal contract value to be 
8        provided to equity eligible contractors and equity 
9        eligible persons as a prerequisite to Program 
10        participation. Any steps taken shall aim to encourage 
11        and grow the meaningful participation of equity 
12        eligible contractors in this State's clean energy 
13        economy. All entities participating under this item 
14        (vi) shall comply with the minimum equity standard set 
15        forth under Section 1-75.    
16            (vii) The remaining capacity shall be allocated by 
17        the Agency in order to respond to market demand. The 
18        Agency shall allocate any discretionary capacity prior 
19        to the beginning of each delivery year. 
20            (viii) The Agency, through its long-term renewable 
21        resources procurement plan, may implement solutions to 
22        maintain stable and consistent REC offerings allocated 
23        to systems described in item (i) of this subparagraph 
24        (K) to avoid gaps in availability during a delivery 
25        year, including, but not limited to, creating a 
26        floating block of REC capacity in a given delivery 
 
 
10400SB0025ham004- 262 -LRB104 16098 AAS 29398 a

1        year.    
2        To the extent there is uncontracted capacity from any 
3    block in any of categories (i) through (vi) at the end of a 
4    delivery year, the Agency shall redistribute that capacity 
5    to one or more other categories giving priority to 
6    categories with projects on a waitlist. The redistributed 
7    capacity shall be added to the annual capacity in the 
8    subsequent delivery year, and the price for renewable 
9    energy credits shall be the price for the new delivery 
10    year. Redistributed capacity shall not be considered 
11    redistributed when determining whether the goals in this 
12    subsection (K) have been met. 
13        Notwithstanding anything to the contrary, as the 
14    Agency increases the capacity in item (vi) to 40% over 
15    time, the Agency may reduce the capacity of items (i) 
16    through (v) proportionate to the capacity of the 
17    categories of projects in item (vi), to achieve a balance 
18    of project types. 
19        The Adjustable Block program shall be designed to 
20    ensure that renewable energy credits are procured from 
21    projects in diverse locations and are not concentrated in 
22    a few regional areas. 
23        (L) Notwithstanding provisions for advancing capital 
24    prior to project energization found in item (vi) of 
25    subparagraph (K), the procurement of photovoltaic 
26    renewable energy credits under items (i) through (vi) of 
 
 
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1    subparagraph (K) of this paragraph (1) shall otherwise be 
2    subject to the following contract and payment terms:
3            (i) (Blank). 
4            (ii) Unless otherwise provided for in the Agency's 
5        approved long-term plan, for For those renewable 
6        energy credits that qualify and are procured under 
7        item (i) of subparagraph (K) of this paragraph (1), 
8        and any similar category projects that are procured 
9        under item (vi) of subparagraph (K) of this paragraph 
10        (1) that qualify and are procured under item (vi), the 
11        contract length shall be 15 years. Beginning on the 
12        effective date of this amendatory Act of the 104th 
13        General Assembly, and including the remainder of 
14        program year 2026-2027, 50% of the renewable energy 
15        credit delivery contract value, based on the estimated 
16        generation during the first 15 years of operation, 
17        shall be paid The renewable energy credit delivery 
18        contract value shall be paid in full, based on the 
19        estimated generation during the first 15 years of 
20        operation, by the contracting utilities at the time 
21        that the facility producing the renewable energy 
22        credits is interconnected at the distribution system 
23        level of the utility and verified as energized and 
24        compliant by the Program Administrator. The remaining 
25        portion of the renewable energy credit delivery 
26        contract value shall be paid ratably over the 
 
 
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1        subsequent 6-year period. Relative to a contract 
2        structure under which the full renewable energy credit 
3        delivery contract value shall be paid in full at the 
4        time of interconnection and verification of 
5        energization, the Agency shall consider the impact of 
6        deferred payments across the subsequent payment period 
7        when establishing renewable energy credit prices. The 
8        electric utility shall receive and retire all 
9        renewable energy credits generated by the project for 
10        the first 15 years of operation. Renewable energy 
11        credits generated by the project thereafter shall not 
12        be transferred under the renewable energy credit 
13        delivery contract with the counterparty electric 
14        utility. 
15            (iii) Unless otherwise provided for in the 
16        Agency's approved long-term plan, for For those 
17        renewable energy credits that qualify and are procured 
18        under item (ii) and (v) of subparagraph (K) of this 
19        paragraph (1) and any like projects similar category    
20        that qualify and are procured under items (iv) and    
21        item (vi), the contract length shall be 15 years. 15% 
22        of the renewable energy credit delivery contract 
23        value, based on the estimated generation during the 
24        first 15 years of operation, shall be paid by the 
25        contracting utilities at the time that the facility 
26        producing the renewable energy credits is 
 
 
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1        interconnected at the distribution system level of the 
2        utility and verified as energized and compliant by the 
3        Program Administrator. The remaining portion shall be 
4        paid ratably over the subsequent 6-year period. The 
5        electric utility shall receive and retire all 
6        renewable energy credits generated by the project for 
7        the first 15 years of operation. Renewable energy 
8        credits generated by the project thereafter shall not 
9        be transferred under the renewable energy credit 
10        delivery contract with the counterparty electric 
11        utility. 
12            (iv) Unless otherwise provided for in the Agency's 
13        approved long-term plan, for For those renewable 
14        energy credits that qualify and are procured under 
15        item items (iii) and (iv) of subparagraph (K) of this 
16        paragraph (1), and any like projects that qualify and 
17        are procured under items (iv) and item (vi), the 
18        renewable energy credit delivery contract length shall 
19        be 20 years and shall be paid over the delivery term, 
20        not to exceed during each delivery year the contract 
21        price multiplied by the estimated annual renewable 
22        energy credit generation amount. If generation of 
23        renewable energy credits during a delivery year 
24        exceeds the estimated annual generation amount, the 
25        excess renewable energy credits shall be carried 
26        forward to future delivery years and shall not expire 
 
 
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1        during the delivery term. If generation of renewable 
2        energy credits during a delivery year, including 
3        carried forward excess renewable energy credits, if 
4        any, is less than the estimated annual generation 
5        amount, payments during such delivery year will not 
6        exceed the quantity generated plus the quantity 
7        carried forward multiplied by the contract price. The 
8        electric utility shall receive all renewable energy 
9        credits generated by the project during the first 20 
10        years of operation and retire all renewable energy 
11        credits paid for under this item (iv) and return at the 
12        end of the delivery term all renewable energy credits 
13        that were not paid for. Renewable energy credits 
14        generated by the project thereafter shall not be 
15        transferred under the renewable energy credit delivery 
16        contract with the counterparty electric utility. 
17        Notwithstanding the preceding, for those projects 
18        participating under item (iii) of subparagraph (K), 
19        the contract price for a delivery year shall be based 
20        on subscription levels as measured on the higher of 
21        the first business day of the delivery year or the 
22        first business day 6 months after the first business 
23        day of the delivery year. Subscription of 90% of 
24        nameplate capacity or greater shall be deemed to be 
25        fully subscribed for the purposes of this item (iv). 
26        For projects receiving a 20-year delivery contract, 
 
 
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1        REC prices shall be adjusted downward for consistency 
2        with the incentive levels previously determined to be 
3        necessary to support projects under 15-year delivery 
4        contracts, taking into consideration any additional 
5        new requirements placed on the projects, including, 
6        but not limited to, labor standards. 
7            (v) Each contract shall include provisions to 
8        ensure the delivery of the estimated quantity of 
9        renewable energy credits and ongoing collateral 
10        requirements and other provisions deemed appropriate 
11        by the Agency. 
12            (vi) The utility shall be the counterparty to the 
13        contracts executed under this subparagraph (L) that 
14        are approved by the Commission under the process 
15        described in Section 16-111.5 of the Public Utilities 
16        Act. No contract shall be executed for an amount that 
17        is less than one renewable energy credit per year.
18            (vii) If, at any time, approved applications for 
19        the Adjustable Block program exceed funds collected by 
20        the electric utility or would cause the Agency to 
21        exceed the limitation described in subparagraph (E) of 
22        this paragraph (1) on the amount of renewable energy 
23        resources that may be procured, then the Agency may 
24        consider future uncommitted funds to be reserved for 
25        these contracts on a first-come, first-served basis.
26            (viii) Nothing in this Section shall require the 
 
 
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1        utility to advance any payment or pay any amounts that 
2        exceed the actual amount of revenues anticipated to be 
3        collected by the utility under paragraph (6) of this 
4        subsection (c) and subsection (k) of Section 16-108 of 
5        the Public Utilities Act inclusive of eligible funds 
6        collected in prior years and alternative compliance 
7        payments for use by the utility. 
8            (ix) Notwithstanding other requirements of this 
9        subparagraph (L), no modification shall be required to 
10        Adjustable Block program contracts if they were 
11        already executed prior to the establishment, approval, 
12        and implementation of new contract forms as a result 
13        of this amendatory Act of the 102nd General Assembly.
14            (x) Contracts may be assignable, but only to 
15        entities first deemed by the Agency to have met 
16        program terms and requirements applicable to direct 
17        program participation. In developing contracts for the 
18        delivery of renewable energy credits, the Agency shall 
19        be permitted to establish fees applicable to each 
20        contract assignment. 
21        (M) The Agency shall be authorized to retain one or 
22    more experts or expert consulting firms to develop, 
23    administer, implement, operate, and evaluate the 
24    Adjustable Block program described in subparagraph (K) of 
25    this paragraph (1), as well as the Geothermal Homes and 
26    Businesses Program described in subparagraph (S) of this 
 
 
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1    paragraph (1), and the Agency shall retain the consultant 
2    or consultants in the same manner, to the extent 
3    practicable, as the Agency retains others to administer 
4    provisions of this Act, including, but not limited to, the 
5    procurement administrator. The selection of experts and 
6    expert consulting firms and the procurement process 
7    described in this subparagraph (M) are exempt from the 
8    requirements of Section 20-10 of the Illinois Procurement 
9    Code, under Section 20-10 of that Code. The Agency shall 
10    strive to minimize administrative expenses in the 
11    implementation of the Adjustable Block program.
12        The Program Administrator may charge application fees 
13    to participating firms to cover the cost of program 
14    administration. Any application fee amounts shall 
15    initially be determined through the long-term renewable 
16    resources procurement plan, and modifications to any 
17    application fee that deviate more than 25% from the 
18    Commission's approved value must be approved by the 
19    Commission as a long-term plan revision under Section 
20    16-111.5 of the Public Utilities Act. The Agency shall 
21    consider stakeholder feedback when making adjustments to 
22    application fees and shall notify stakeholders in advance 
23    of any planned changes. 
24        In addition to covering the costs of program 
25    administration, the Agency, in conjunction with its 
26    Program Administrator, may also use the proceeds of such 
 
 
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1    fees charged to participating firms to support public 
2    education and ongoing regional and national coordination 
3    with nonprofit organizations, public bodies, and others 
4    engaged in the implementation of renewable energy 
5    incentive programs or similar initiatives. This work may 
6    include developing papers and reports, hosting regional 
7    and national conferences, and other work deemed necessary 
8    by the Agency to position the State of Illinois as a 
9    national leader in renewable energy incentive program 
10    development and administration. 
11        The Agency and its consultant or consultants shall 
12    monitor block activity, share program activity with 
13    stakeholders and conduct quarterly meetings to discuss 
14    program activity and market conditions. If necessary, the 
15    Agency may make prospective administrative adjustments to 
16    the Adjustable Block program and the Geothermal Homes and 
17    Businesses Program design, such as making adjustments to 
18    purchase prices as necessary to achieve the goals of this 
19    subsection (c). Program modifications to any block price 
20    that do not deviate from the Commission's approved value 
21    by more than 10% shall take effect immediately and are not 
22    subject to Commission review and approval. Program 
23    modifications to any block price that deviate more than 
24    10% from the Commission's approved value must be approved 
25    by the Commission as a long-term plan amendment under 
26    Section 16-111.5 of the Public Utilities Act. The Agency 
 
 
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1    shall consider stakeholder feedback when making 
2    adjustments to the Adjustable Block and the Geothermal 
3    Homes and Businesses Program design and shall notify 
4    stakeholders in advance of any planned changes.
5        The Agency and its program administrators for both the 
6    Adjustable Block program, and the Illinois Solar for All 
7    Program, and the Geothermal Homes and Businesses Program    
8    consistent with the requirements of this subsection (c) 
9    and subsection (b) of Section 1-56 of this Act, shall 
10    propose the Adjustable Block program terms, conditions, 
11    and requirements, including the prices to be paid for 
12    renewable energy credits, where applicable, and 
13    requirements applicable to participating entities and 
14    project applications, through the development, review, and 
15    approval of the Agency's long-term renewable resources 
16    procurement plan described in this subsection (c) and 
17    paragraph (5) of subsection (b) of Section 16-111.5 of the 
18    Public Utilities Act. Terms, conditions, and requirements 
19    for program participation shall include the following:
20            (i) The Agency shall establish a registration 
21        process for entities seeking to qualify for 
22        program-administered incentive funding and establish 
23        baseline qualifications for vendor approval. The 
24        Agency shall also establish program requirements and 
25        minimum contract terms for vendors and others involved 
26        in the marketing, sale, installation, and financing of 
 
 
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1        distributed generation systems and community solar 
2        subscriptions to prevent misleading marketing and 
3        abusive practices and to otherwise protect customers.    
4        The Agency must maintain a list of approved entities 
5        on each program's website, and may revoke a vendor's 
6        ability to receive program-administered incentive 
7        funding status upon a determination that the vendor 
8        failed to comply with contract terms, the law, or 
9        other program requirements.
10            (ii) The Agency shall establish program 
11        requirements and minimum contract terms to ensure 
12        projects are properly installed and produce their 
13        expected amounts of energy. Program requirements may 
14        include on-site inspections and photo documentation of 
15        projects under construction. The Agency may require 
16        repairs, alterations, or additions to remedy any 
17        material deficiencies discovered. Vendors who have a 
18        disproportionately high number of deficient systems 
19        may lose their eligibility to continue to receive 
20        State-administered incentive funding through Agency 
21        programs and procurements.
22            (iii) To discourage deceptive marketing or other 
23        bad faith business practices, the Agency may require 
24        direct program participants, including agents 
25        operating on their behalf, to provide standardized 
26        disclosures to a customer prior to that customer's 
 
 
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1        execution of a contract for the development of a 
2        distributed generation system, or a subscription to a 
3        community solar project, or the development of a 
4        geothermal heating and cooling system.
5            (iv) The Agency shall establish one or multiple 
6        Consumer Complaints Centers to accept complaints 
7        regarding businesses that participate in, or otherwise 
8        benefit from, State-administered incentive funding 
9        through Agency-administered programs. The Agency shall 
10        maintain a public database of complaints with any 
11        confidential or particularly sensitive information 
12        redacted from public entries.
13            (v) Through a filing in the proceeding for the 
14        approval of its long-term renewable energy resources 
15        procurement plan, the Agency shall provide an annual 
16        written report to the Illinois Commerce Commission 
17        documenting the frequency and nature of complaints and 
18        any enforcement actions taken in response to those 
19        complaints.
20            (vi) The Agency shall schedule regular meetings 
21        with representatives of the Office of the Attorney 
22        General, the Illinois Commerce Commission, consumer 
23        protection groups, and other interested stakeholders 
24        to share relevant information about consumer 
25        protection, project compliance, and complaints 
26        received.
 
 
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1            (vii) To the extent that complaints received 
2        implicate the jurisdiction of the Office of the 
3        Attorney General, the Illinois Commerce Commission, or 
4        local, State, or federal law enforcement, the Agency 
5        shall also refer complaints to those entities as 
6        appropriate. 
7            (viii) The Agency may, at its discretion, 
8        establish a registration process for entities, or a 
9        subset of entities, that provide financing for 
10        consumers for the purchase of distributed renewable 
11        generation devices. The Agency may establish baseline 
12        qualifications for financing entity approval, 
13        including defining the circumstances under which 
14        financing entities may be subject to registration. The 
15        Agency may also establish program requirements for 
16        entities that provide financing for the purchase of 
17        distributed renewable generation devices, which may 
18        include marketing and disclosure requirements, other 
19        requirements as further defined by the Agency through 
20        its long-term plan, and any consumer protection 
21        requirements developed or modified thereto. If the 
22        Agency establishes a registration process for 
23        financing entities, the Agency may revoke a financing 
24        entity's approval in a program upon a determination 
25        that the financing entity failed to comply with 
26        contract terms, the law, or other program 
 
 
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1        requirements. The Agency may also establish program 
2        requirements that prohibit distributed renewable 
3        generation devices intending to apply for 
4        program-administered incentive funding from receiving 
5        program funding if the consumer's purchase of the 
6        device was financed by an entity whose approval status 
7        in the program has been revoked. These registration 
8        requirements may apply to entities that finance 
9        projects intended to apply for program-administered 
10        incentive funding even if those entities do not 
11        receive any portion of the program-administered 
12        incentive funding.
13            (ix) The Agency, at its discretion, may require 
14        that vendors, as part of the application and annual 
15        recertification process, present the Agency or its 
16        designee with a security bond equal to an amount 
17        determined to be reasonable by the Agency. The bond 
18        shall be for the benefit of customers harmed by the 
19        vendor's violation of Agency requirements or other 
20        applicable laws or regulations. The Agency may 
21        determine that it is reasonable to have no bond 
22        requirement for some categories of vendors or enhanced 
23        bond requirements for vendors that the Agency has 
24        deemed to pose more acute risks.
25            (x) For distributed renewable generation devices, 
26        the Agency may, in its discretion, establish 
 
 
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1        provisions that restrict, prohibit, or create 
2        additional requirements for distributed renewable 
3        generation device sales or financing offers through 
4        which the customer is promised the pass-through of a 
5        portion or all of the payments received by the 
6        approved vendor for the delivery of renewable energy 
7        credits only after the receipt of such payment by the 
8        approved vendor. The requirements may include the use 
9        of an escrow process developed by the Agency through 
10        which renewable energy credit payments are made to an 
11        escrow agent who then disburses the promised amount to 
12        the customer and the remainder to the vendor. The 
13        requirements in this item (x) shall in no way prohibit 
14        the upfront discounting of the purchase price, lease 
15        payment, or power purchase agreement rate based on the 
16        anticipated receipt of renewable energy credit 
17        contract payments by the approved vendor.
18            (xi) To the extent that distributed renewable 
19        generation device sales or financing offers through 
20        which the customer is promised the pass-through of a 
21        portion or all of the payments received by the vendor 
22        for the delivery of renewable energy credits after the 
23        receipt of such payment by the vendor are permitted, 
24        the following requirements may be implemented, at the 
25        Agency's discretion, in a time and manner determined 
26        by the Agency:
 
 
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1                (I) the vendor shall submit proof of customer 
2            payments to the Agency as the Agency deems 
3            necessary; and
4                (II) the vendor shall represent and warrant on 
5            a form developed by the Agency that the vendor is 
6            not insolvent, has not voluntarily filed for 
7            bankruptcy, and has not been subject to or 
8            threatened with involuntary insolvency.
9            (xii) To ensure that customers receive full and 
10        uninterrupted benefits and services promised by 
11        vendors, the Agency may propose additional solutions 
12        through its long-term renewable resources procurement 
13        plan described in this subsection (c) and paragraph 
14        (5) of subsection (b) of Section 16-111.5 of the 
15        Public Utilities Act. The solutions may allow for 
16        collections made pursuant to subsection (k) of Section 
17        16-108 of the Public Utilities Act to support the 
18        programs and procurements outlined in paragraph (1) of 
19        subsection (c) of this Section to be leveraged to (1) 
20        ensure that a vendor's promised payments are received 
21        by customers, (2) incentivize vendors to establish 
22        service agreements with customers whose original 
23        vendor has become nonresponsive, (3) ensure that 
24        customers receive restitution for financial harm 
25        proven to be caused by a program vendor or its 
26        designee, or (4) otherwise ensure that customers do 
 
 
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1        not suffer loss or harm through activities supported 
2        by the Adjustable Block program and the Illinois Solar 
3        for All Program.    
4        (N) The Agency shall establish the terms, conditions, 
5    and program requirements for photovoltaic community 
6    renewable generation projects with a goal to expand access 
7    to a broader group of energy consumers, to ensure robust 
8    participation opportunities for residential and small 
9    commercial customers and those who cannot install 
10    renewable energy on their own properties. Subject to 
11    reasonable limitations, any plan approved by the 
12    Commission shall allow subscriptions to community 
13    renewable generation projects to be portable and 
14    transferable. For purposes of this subparagraph (N), 
15    "portable" means that subscriptions may be retained by the 
16    subscriber even if the subscriber relocates or changes its 
17    address within the same utility service territory; and 
18    "transferable" means that a subscriber may assign or sell 
19    subscriptions to another person within the same utility 
20    service territory.
21        Through the development of its long-term renewable 
22    resources procurement plan, the Agency may consider 
23    whether community renewable generation projects utilizing 
24    technologies other than photovoltaics should be supported 
25    through State-administered incentive funding, and may 
26    issue requests for information to gauge market demand. 
 
 
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1        Electric utilities shall provide a monetary credit to 
2    a subscriber's subsequent bill for service for the 
3    proportional output of a community renewable generation 
4    project attributable to that subscriber as specified in 
5    Section 16-107.5 of the Public Utilities Act.
6        The Agency shall purchase renewable energy credits 
7    from subscribed shares of photovoltaic community renewable 
8    generation projects through the Adjustable Block program 
9    described in subparagraph (K) of this paragraph (1) or 
10    through the Illinois Solar for All Program described in 
11    Section 1-56 of this Act. The electric utility shall 
12    purchase any unsubscribed energy from community renewable 
13    generation projects that are Qualifying Facilities ("QF") 
14    under the electric utility's tariff for purchasing the 
15    output from QFs under Public Utilities Regulatory Policies 
16    Act of 1978. 
17        The owners of and any subscribers to a community 
18    renewable generation project shall not be considered 
19    public utilities or alternative retail electricity 
20    suppliers under the Public Utilities Act solely as a 
21    result of their interest in or subscription to a community 
22    renewable generation project and shall not be required to 
23    become an alternative retail electric supplier by 
24    participating in a community renewable generation project 
25    with a public utility.
26        (O) For the delivery year beginning June 1, 2018, the 
 
 
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1    long-term renewable resources procurement plan required by 
2    this subsection (c) shall provide for the Agency to 
3    procure contracts to continue offering the Illinois Solar 
4    for All Program described in subsection (b) of Section 
5    1-56 of this Act, and the contracts approved by the 
6    Commission shall be executed by the utilities that are 
7    subject to this subsection (c). The long-term renewable 
8    resources procurement plan shall allocate up to 
9    $50,000,000 per delivery year to fund the programs, and 
10    the plan shall determine the amount of funding to be 
11    apportioned to the programs identified in subsection (b) 
12    of Section 1-56 of this Act; provided that for the 
13    delivery years beginning June 1, 2021, June 1, 2022, and 
14    June 1, 2023, the long-term renewable resources 
15    procurement plan may average the annual budgets over a 
16    3-year period to account for program ramp-up. For the 
17    delivery years beginning June 1, 2021, June 1, 2024, June 
18    1, 2027, and June 1, 2030 and additional $10,000,000 shall 
19    be provided to the Department of Commerce and Economic 
20    Opportunity to implement the workforce development 
21    programs and reporting as outlined in Section 16-108.12 of 
22    the Public Utilities Act. In making the determinations 
23    required under this subparagraph (O), the Commission shall 
24    consider the experience and performance under the programs 
25    and any evaluation reports. The Commission shall also 
26    provide for an independent evaluation of those programs on 
 
 
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1    a periodic basis that are funded under this subparagraph 
2    (O).
3        (P) All programs and procurements under this 
4    subsection (c) shall be designed to encourage 
5    participating projects to use a diverse and equitable 
6    workforce and a diverse set of contractors, including 
7    minority-owned businesses, disadvantaged businesses, 
8    trade unions, graduates of any workforce training programs 
9    administered under this Act, and small businesses.
10        The Agency shall develop a method to optimize 
11    procurement of renewable energy credits from proposed 
12    utility-scale projects that are located in communities 
13    eligible to receive Energy Transition Community Grants 
14    pursuant to Section 10-20 of the Energy Community 
15    Reinvestment Act. If this requirement conflicts with other 
16    provisions of law or the Agency determines that full 
17    compliance with the requirements of this subparagraph (P) 
18    would be unreasonably costly or administratively 
19    impractical, the Agency is to propose alternative 
20    approaches to achieve development of renewable energy 
21    resources in communities eligible to receive Energy 
22    Transition Community Grants pursuant to Section 10-20 of 
23    the Energy Community Reinvestment Act or seek an exemption 
24    from this requirement from the Commission. 
25        (Q) Each facility listed in subitems (i) through (ix) 
26    of item (1) of this subparagraph (Q) for which a renewable 
 
 
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1    energy credit delivery contract is signed after the 
2    effective date of this amendatory Act of the 102nd General 
3    Assembly is subject to the following requirements through 
4    the Agency's long-term renewable resources procurement 
5    plan:
6            (1) Each facility shall be subject to the 
7        prevailing wage requirements included in the 
8        Prevailing Wage Act. The Agency shall require 
9        verification that all construction performed on the 
10        facility by the renewable energy credit delivery 
11        contract holder, its contractors, or its 
12        subcontractors relating to construction of the 
13        facility is performed by construction employees 
14        receiving an amount for that work equal to or greater 
15        than the general prevailing rate, as that term is 
16        defined in Section 2 3 of the Prevailing Wage Act. For 
17        purposes of this item (1), "house of worship" means 
18        property that is both (1) used exclusively by a 
19        religious society or body of persons as a place for 
20        religious exercise or religious worship and (2) 
21        recognized as exempt from taxation pursuant to Section 
22        15-40 of the Property Tax Code. This item (1) shall 
23        apply to any of the following: 
24                (i) all new utility-scale wind projects;
25                (ii) all new utility-scale photovoltaic 
26            projects and repowered wind projects;
 
 
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1                (iii) all new brownfield photovoltaic 
2            projects;
3                (iv) all new photovoltaic community renewable 
4            energy facilities that qualify for item (iii) of 
5            subparagraph (K) of this paragraph (1);
6                (v) all new community driven community 
7            photovoltaic projects that qualify for item (v) of 
8            subparagraph (K) of this paragraph (1);
9                (vi) all new photovoltaic projects on public 
10            school land that qualify for item (iv) of 
11            subparagraph (K) of this paragraph (1);
12                (vii) all new photovoltaic distributed 
13            renewable energy generation devices that (1) 
14            qualify for item (i) of subparagraph (K) of this 
15            paragraph (1); (2) are not projects that serve 
16            single-family or multi-family residential 
17            buildings; and (3) are not houses of worship where 
18            the aggregate capacity including colocated    
19            collocated projects would not exceed 100 
20            kilowatts;
21                (viii) all new photovoltaic distributed 
22            renewable energy generation devices that (1) 
23            qualify for item (ii) of subparagraph (K) of this 
24            paragraph (1); (2) are not projects that serve 
25            single-family or multi-family residential 
26            buildings; and (3) are not houses of worship where 
 
 
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1            the aggregate capacity including colocated    
2            collocated projects would not exceed 100 
3            kilowatts;
4                (ix) all new, modernized, or retooled 
5            hydropower facilities;
6                (x) all new geothermal heating and cooling 
7            systems awarded through the Geothermal Homes and 
8            Businesses Program under subparagraph (S) of this 
9            paragraph (1) that do not serve (1) single-family 
10            residential buildings, (2) multi-family 
11            residential buildings with aggregate geothermal 
12            system tonnage, including colocated projects, of 
13            no more than 29 tons, or (3) houses of worship with 
14            aggregate geothermal system tonnage, including 
15            colocated projects, of no more than 29 tons. 
16            (2) Renewable energy credits procured from new 
17        utility-scale wind projects, new utility-scale solar 
18        projects, new brownfield solar projects, repowered 
19        wind projects, and retooled hydropower facilities 
20        pursuant to Agency procurement events occurring after 
21        the effective date of this amendatory Act of the 102nd 
22        General Assembly and photovoltaic community renewable 
23        generation projects where the aggregate capacity, 
24        including colocated projects, exceeds 3,000 kilowatts 
25        pursuant to a renewable energy credit delivery 
26        contract approved by the Illinois Commerce Commission 
 
 
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1        under the Adjustable Block Program after the effective 
2        date of this amendatory Act of the 104th General 
3        Assembly must be from facilities built by general 
4        contractors that must enter into a project labor 
5        agreement, as defined by this Act, prior to 
6        construction. Photovoltaic community renewable 
7        generation projects on a program waitlist as of the 
8        effective date of this amendatory Act of the 104th 
9        General Assembly awarded capacity for the program year 
10        commencing June 1, 2026 or any program year thereafter 
11        shall not be exempt from the project labor agreement 
12        requirements of this item (2). The project labor 
13        agreement shall be filed with the Director in 
14        accordance with procedures established by the Agency 
15        through its long-term renewable resources procurement 
16        plan. Any information submitted to the Agency in this 
17        item (2) shall be considered commercially sensitive 
18        information. At a minimum, the project labor agreement 
19        must provide the names, addresses, and occupations of 
20        the owner of the plant and the individuals 
21        representing the labor organization employees 
22        participating in the project labor agreement 
23        consistent with the Project Labor Agreements Act. The 
24        agreement must also specify the terms and conditions 
25        as defined by this Act.
26            (2.5) Energy storage credits procured from battery 
 
 
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1        storage projects pursuant to Agency procurement events 
2        and additional energy storage resources procured in 
3        accordance with subparagraph (B) of paragraph (3) of 
4        subsection (d-20) of this Section pursuant to Agency 
5        procurement events occurring after the effective date 
6        of this amendatory Act of the 104th General Assembly 
7        must be from facilities built by general contractors 
8        that must enter into a project labor agreement prior 
9        to construction. The project labor agreement shall be 
10        filed with the Director in accordance with procedures 
11        established by the Agency through its long-term 
12        renewable resources procurement plan. Any information 
13        submitted to the Agency pursuant to this item (2.5) 
14        shall be considered commercially sensitive 
15        information. At a minimum, the project labor agreement 
16        must provide the names, addresses, and occupations of 
17        the owner of the plant and the individuals 
18        representing the labor organization employees 
19        participating in the project labor agreement 
20        consistent with the Project Labor Agreements Act. The 
21        agreement must also specify the terms and conditions, 
22        as defined by this Act.    
23            (3) It is the intent of this Section to ensure that 
24        economic development occurs across Illinois 
25        communities, that emerging businesses may grow, and 
26        that there is improved access to the clean energy 
 
 
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1        economy by persons who have greater economic burdens 
2        to success. The Agency shall take into consideration 
3        the unique cost of compliance of this subparagraph (Q) 
4        that might be borne by equity eligible contractors, 
5        shall include such costs when determining the price of 
6        renewable energy credits in the Adjustable Block 
7        program and the Geothermal Homes and Businesses 
8        Program, and shall take such costs into consideration 
9        in a nondiscriminatory manner when comparing bids for 
10        competitive procurements. The Agency shall consider 
11        costs associated with compliance whether in the 
12        development, financing, or construction of projects. 
13        The Agency shall periodically review the assumptions 
14        in these costs and may adjust prices, in compliance 
15        with subparagraph (M) of this paragraph (1).
16        (R) In its long-term renewable resources procurement 
17    plan, the Agency shall establish a self-direct renewable 
18    portfolio standard compliance program for eligible 
19    self-direct customers that purchase renewable energy 
20    credits from utility-scale wind and solar projects through 
21    long-term agreements for purchase of renewable energy 
22    credits as described in this Section. Such long-term 
23    agreements may include the purchase of energy or other 
24    products on a physical or financial basis and may involve 
25    an alternative retail electric supplier as defined in 
26    Section 16-102 of the Public Utilities Act. This program 
 
 
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1    shall take effect in the delivery year commencing June 1, 
2    2023.
3            (1) For the purposes of this subparagraph:
4            "Eligible self-direct customer" means any retail 
5        customers of an electric utility that serves 3,000,000 
6        or more retail customers in the State and whose total 
7        highest 30-minute demand was more than 10,000 
8        kilowatts, or any retail customers of an electric 
9        utility that serves less than 3,000,000 retail 
10        customers but more than 500,000 retail customers in 
11        the State and whose total highest 15-minute demand was 
12        more than 10,000 kilowatts.
13            "Retail customer" has the meaning set forth in 
14        Section 16-102 of the Public Utilities Act and 
15        multiple retail customer accounts under the same 
16        corporate parent may aggregate their account demands 
17        to meet the 10,000 kilowatt threshold. The criteria 
18        for determining whether this subparagraph is 
19        applicable to a retail customer shall be based on the 
20        12 consecutive billing periods prior to the start of 
21        the year in which the application is filed.
22            (2) For renewable energy credits to count toward 
23        the self-direct renewable portfolio standard 
24        compliance program, they must:
25                (i) qualify as renewable energy credits as 
26            defined in Section 1-10 of this Act;
 
 
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1                (ii) be sourced from one or more renewable 
2            energy generating facilities that comply with the 
3            geographic requirements as set forth in 
4            subparagraph (I) of paragraph (1) of subsection 
5            (c) as interpreted through the Agency's long-term 
6            renewable resources procurement plan, or, where 
7            applicable, the geographic requirements that 
8            governed utility-scale renewable energy credits at 
9            the time the eligible self-direct customer entered 
10            into the applicable renewable energy credit 
11            purchase agreement;
12                (iii) be procured through long-term contracts 
13            with term lengths of at least 10 years either 
14            directly with the renewable energy generating 
15            facility or through a bundled power purchase 
16            agreement, a virtual power purchase agreement, an 
17            agreement between the renewable generating 
18            facility, an alternative retail electric supplier, 
19            and the customer, or such other structure as is 
20            permissible under this subparagraph (R);
21                (iv) be equivalent in volume to at least 40% 
22            of the eligible self-direct customer's usage, 
23            determined annually by the eligible self-direct 
24            customer's usage during the previous delivery 
25            year, measured to the nearest megawatt-hour;
26                (v) be retired by or on behalf of the large 
 
 
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1            energy customer;
2                (vi) be sourced from new utility-scale wind 
3            projects or new utility-scale solar projects; and
4                (vii) if the contracts for renewable energy 
5            credits are entered into after the effective date 
6            of this amendatory Act of the 102nd General 
7            Assembly, the new utility-scale wind projects or 
8            new utility-scale solar projects must comply with 
9            the requirements established in subparagraphs (P) 
10            and (Q) of paragraph (1) of this subsection (c) 
11            and subsection (c-10).
12            (3) The self-direct renewable portfolio standard 
13        compliance program shall be designed to allow eligible 
14        self-direct customers to procure new renewable energy 
15        credits from new utility-scale wind projects or new 
16        utility-scale photovoltaic projects. The Agency shall 
17        annually determine the amount of utility-scale 
18        renewable energy credits it will include each year 
19        from the self-direct renewable portfolio standard 
20        compliance program, subject to receiving qualifying 
21        applications. In making this determination, the Agency 
22        shall evaluate publicly available analyses and studies 
23        of the potential market size for utility-scale 
24        renewable energy long-term purchase agreements by 
25        commercial and industrial energy customers and make 
26        that report publicly available. If demand for 
 
 
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1        participation in the self-direct renewable portfolio 
2        standard compliance program exceeds availability, the 
3        Agency shall ensure participation is evenly split 
4        between commercial and industrial users to the extent 
5        there is sufficient demand from both customer classes. 
6        Each renewable energy credit procured pursuant to this 
7        subparagraph (R) by a self-direct customer shall 
8        reduce the total volume of renewable energy credits 
9        the Agency is otherwise required to procure from new 
10        utility-scale projects pursuant to subparagraph (C) of 
11        paragraph (1) of this subsection (c) on behalf of 
12        contracting utilities where the eligible self-direct 
13        customer is located. The self-direct customer shall 
14        file an annual compliance report with the Agency 
15        pursuant to terms established by the Agency through 
16        its long-term renewable resources procurement plan to 
17        be eligible for participation in this program. 
18        Customers must provide the Agency with their most 
19        recent electricity billing statements or other 
20        information deemed necessary by the Agency to 
21        demonstrate they are an eligible self-direct customer.
22            (4) The Commission shall approve a reduction in 
23        the volumetric charges collected pursuant to Section 
24        16-108 of the Public Utilities Act for approved 
25        eligible self-direct customers equivalent to the 
26        anticipated cost of renewable energy credit deliveries 
 
 
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1        under contracts for new utility-scale wind and new 
2        utility-scale solar entered for each delivery year 
3        after the large energy customer begins retiring 
4        eligible new utility-scale utility scale renewable 
5        energy credits for self-compliance. The self-direct 
6        credit amount shall be determined annually and is 
7        equal to the estimated portion of the cost authorized 
8        by subparagraph (E) of paragraph (1) of this 
9        subsection (c) that supported the annual procurement 
10        of utility-scale renewable energy credits in the prior 
11        delivery year using a methodology described in the 
12        long-term renewable resources procurement plan, 
13        expressed on a per kilowatthour basis, and does not 
14        include (i) costs associated with any contracts 
15        entered into before the delivery year in which the 
16        customer files the initial compliance report to be 
17        eligible for participation in the self-direct program, 
18        and (ii) costs associated with procuring renewable 
19        energy credits through existing and future contracts 
20        through the Adjustable Block Program, subsection (c-5) 
21        of this Section 1-75, and the Solar for All Program. 
22        The Agency shall assist the Commission in determining 
23        the current and future costs. The Agency must 
24        determine the self-direct credit amount for new and 
25        existing eligible self-direct customers and submit 
26        this to the Commission in an annual compliance filing. 
 
 
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1        The Commission must approve the self-direct credit 
2        amount by June 1, 2023 and June 1 of each delivery year 
3        thereafter.
4            (5) Customers described in this subparagraph (R) 
5        shall apply, on a form developed by the Agency, to the 
6        Agency to be designated as a self-direct eligible 
7        customer. Once the Agency determines that a 
8        self-direct customer is eligible for participation in 
9        the program, the self-direct customer will remain 
10        eligible until the end of the term of the contract. 
11        Thereafter, application may be made not less than 12 
12        months before the filing date of the long-term 
13        renewable resources procurement plan described in this 
14        Act. At a minimum, such application shall contain the 
15        following:
16                (i) the customer's certification that, at the 
17            time of the customer's application, the customer 
18            qualifies to be a self-direct eligible customer, 
19            including documents demonstrating that 
20            qualification;
21                (ii) the customer's certification that the 
22            customer has entered into or will enter into by 
23            the beginning of the applicable procurement year, 
24            one or more bilateral contracts for new wind 
25            projects or new photovoltaic projects, including 
26            supporting documentation;
 
 
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1                (iii) certification that the contract or 
2            contracts for new renewable energy resources are 
3            long-term contracts with term lengths of at least 
4            10 years, including supporting documentation;
5                (iv) certification of the quantities of 
6            renewable energy credits that the customer will 
7            purchase each year under such contract or 
8            contracts, including supporting documentation;
9                (v) proof that the contract is sufficient to 
10            produce renewable energy credits to be equivalent 
11            in volume to at least 40% of the large energy 
12            customer's usage from the previous delivery year, 
13            measured to the nearest megawatt-hour; and
14                (vi) certification that the customer intends 
15            to maintain the contract for the duration of the 
16            length of the contract.
17            (6) If a customer receives the self-direct credit 
18        but fails to properly procure and retire renewable 
19        energy credits as required under this subparagraph 
20        (R), the Commission, on petition from the Agency and 
21        after notice and hearing, may direct such customer's 
22        utility to recover the cost of the wrongfully received 
23        self-direct credits plus interest through an adder to 
24        charges assessed pursuant to Section 16-108 of the 
25        Public Utilities Act. Self-direct customers who 
26        knowingly fail to properly procure and retire 
 
 
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1        renewable energy credits and do not notify the Agency 
2        are ineligible for continued participation in the 
3        self-direct renewable portfolio standard compliance 
4        program.
5        (S) Beginning with the long-term renewable resources 
6    procurement plan covering program and procurement activity 
7    for the delivery year beginning on June 1, 2028, any 
8    long-term renewable resources procurement plan developed 
9    by the Agency in accordance with subparagraph (A) of this 
10    paragraph (1) shall include a Geothermal Homes and 
11    Businesses Program for the procurement of geothermal 
12    renewable energy credits from new geothermal heating and 
13    cooling systems. The long-term renewable resources 
14    procurement plan shall allocate up to $10,000,000 per 
15    delivery year to fund the Program as described in this 
16    subparagraph (S). The Program shall be designed to 
17    stimulate the steady, predictable, and sustainable growth 
18    of new geothermal heating and cooling system deployment in 
19    this State and meet gaps in the marketplace. To this end, 
20    the Geothermal Homes and Businesses Program shall provide 
21    a transparent annual schedule of prices and quantities to 
22    enable the geothermal heating and cooling market to scale 
23    up and renewable energy credit prices to adjust at a 
24    predictable rate over time. The prices set by the 
25    Geothermal Homes and Businesses Program may be reflected 
26    as a set value or as the product of a formula.
 
 
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1                (i) The Geothermal Homes and Businesses Program 
2        shall allocate blocks of renewable energy credits as 
3        follows:
4                (1) The Agency may create categories for the 
5            Program based on structure features and use cases, 
6            including categories based on the nature and size 
7            of the Program's projects, customers, communities 
8            in which a project is located, and other 
9            attributes, defined at the discretion of the 
10            Agency through its long-term plan.    
11                (2) The Agency shall propose an initial single 
12            annual block for each Program delivery year for 
13            each category it creates through the delivery year 
14            beginning on June 1, 2035. The Program shall 
15            include the following for eligible projects for 
16            each delivery year: (I) a block of geothermal 
17            renewable energy credit volumes; (II) a price for 
18            renewable energy credits from geothermal heating 
19            and cooling systems within the identified block; 
20            and (III) the terms and conditions for securing a 
21            spot on a waitlist once the block is fully 
22            committed or reserved. The Agency may periodically 
23            review its prior decisions establishing the amount 
24            of geothermal renewable energy credit volumes in 
25            each annual block and the purchase price for each 
26            block and may propose, on an expedited basis, 
 
 
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1            changes to the previously set values, including, 
2            but not limited to, redistributing the amounts and 
3            the available funds as necessary and appropriate, 
4            subject to Commission approval. The Agency may 
5            define different block sizes, purchase prices, or 
6            other distinct terms and conditions for projects 
7            located in different utility service territories 
8            if the Agency deems it necessary.
9                (3) The Agency may develop an intra-year and 
10            year-to-year waitlist and block reservation policy 
11            that balances market certainty, program 
12            availability, and expedient project deployment.
13                (4) For the program year beginning on June 1, 
14            2028, at least 33% of each annual block shall be 
15            available to be reserved for systems that are 
16            residential, as defined by the Agency. The Agency 
17            shall endeavor to ensure at least 40% of each 
18            annual block is available to be reserved by 
19            systems located in Equity Investment Eligible 
20            Communities. At least 10% of all annual blocks 
21            shall be available to be reserved by systems from 
22            applicants that are equity eligible contractors, 
23            and the Agency shall propose to increase the 
24            percentage of systems from applicants that are 
25            equity eligible contractors over time to 40% based 
26            on factors that include, but are not limited to, 
 
 
10400SB0025ham004- 298 -LRB104 16098 AAS 29398 a

1            the number of equity eligible contractors and the 
2            volume used under this clause (4) in previous 
3            delivery years. For long-term renewable resources 
4            procurement plans developed thereafter, the Agency 
5            may propose adjustments to the minimum percentages 
6            based on developer interest, market interest and 
7            availability, and other factors.
8                (5) The Agency shall establish Program 
9            eligibility requirements that ensure that systems 
10            that enter the Program are sufficiently mature 
11            enough to indicate a demonstrable path to 
12            completion and other terms, conditions, and 
13            requirements for the program, including vendor 
14            registration and approval, sales and marketing 
15            requirements, and other consumer protection 
16            requirements as the Agency deems necessary.
17                (6) The Program shall be designed to ensure 
18            that geothermal renewable energy credits are 
19            procured from projects in diverse locations and 
20            are not procured from projects that are 
21            concentrated in a few regional areas.
22                (7) The Agency, through its long-term 
23            renewable resources procurement plan, may 
24            implement solutions to maintain stable and 
25            consistent REC offerings to avoid gaps in 
26            availability during a delivery year, including, 
 
 
10400SB0025ham004- 299 -LRB104 16098 AAS 29398 a

1            but not limited to, creating a floating block of 
2            REC capacity in a given delivery year.
3            (ii) Energy derived from a geothermal heating and 
4        cooling system shall be eligible for inclusion in 
5        meeting the requirements of the Program. Geothermal 
6        renewable energy credits shall be expressed in 
7        megawatt-hour units. To make this calculation, the 
8        Agency (1) shall identify an appropriate formula 
9        supported by a geothermal industry trade organization, 
10        a national laboratory, or another data-backed and 
11        verifiable methodology, (2) may propose adjustments to 
12        any formulas for its proposed renewable energy credit 
13        calculation methodology, and (3) may reflect 
14        calculation methodologies already in use for other 
15        State renewable portfolio standards, if applicable and 
16        appropriate. The Agency shall determine the form and 
17        manner in which the renewable energy credits are 
18        verified and retired, in accordance with national best 
19        practices.
20            Geothermal renewable energy credits retired by 
21        obligated utilities for compliance with the Program 
22        are only valid for compliance if those geothermal 
23        renewable energy credits have not been previously 
24        retired by another entity that is not the obligated 
25        utility on any tracking system, carbon registry, or 
26        other accounting mechanism at any time. Additionally, 
 
 
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1        geothermal renewable energy credits retired by 
2        obligated utilities for compliance with the Program 
3        shall only be valid for compliance if those geothermal 
4        renewable energy credits have not been used to 
5        substantiate a public emissions or energy usage claim 
6        by any other another entity that is not the obligated 
7        utility, of any type and at any time, whether or not 
8        the geothermal renewable energy credits were actually 
9        retired on a tracking system, registry, or other 
10        accounting mechanism at the time of the public 
11        emissions-based claim. Geothermal renewable energy 
12        credits generated for compliance with the Program 
13        shall be valid only if retired once, and claimed once, 
14        by the obligated utility.
15            In order to promote the competitive development of 
16        geothermal heating and cooling systems in furtherance 
17        of this State's interest in the health, safety, and 
18        welfare of its residents, renewable energy credits 
19        from geothermal heating and cooling systems shall not 
20        be eligible for purchase and retirement under this Act 
21        if the credits are sourced from a geothermal heating 
22        and cooling system for which costs are being recovered 
23        on or after the effective date of this amendatory Act 
24        of the 104th General Assembly through rates regulated 
25        by this State or any other state.
26            (iii) The Agency shall establish Program 
 
 
10400SB0025ham004- 301 -LRB104 16098 AAS 29398 a

1        requirements and minimum contract terms to ensure that 
2        projects are properly installed and that projects 
3        operate to the level of expected benefits. The 
4        contract terms shall include, but are not limited to, 
5        the following:
6                (1) The capital that is not advanced shall be 
7            disbursed upon a schedule determined by the 
8            Agency, based on the total contracted fulfillment 
9            over the delivery term, not to exceed, during each 
10            delivery year, the contract price multiplied by 
11            the estimated annual renewable energy credit 
12            generation amount. Payment structures shall 
13            include provisions that provide portions of the 
14            renewable energy credit delivery contract value 
15            upon energization, including no less than 40% of 
16            the contract value for residential projects, based 
17            on the estimated renewable energy credit 
18            production during the contract term.
19                (2) For renewable energy credits that qualify 
20            and are procured under the Program, the delivery 
21            contract length shall be 15 years.
22                (3) For contracts that are paid upon the 
23            delivery of renewable energy credits, if 
24            generation of renewable energy credits from 
25            geothermal heating and cooling systems during a 
26            delivery year exceeds the estimated annual 
 
 
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1            generation amount, the excess of such renewable 
2            energy credits shall be carried forward to future 
3            delivery years and shall not expire during the 
4            delivery term. If the renewable energy credit 
5            generation during a delivery year, including any 
6            carried forward excess renewable energy credits, 
7            is less than the estimated annual generation 
8            amount, payments during the delivery year shall 
9            not exceed the quantity generated plus the 
10            quantity carried forward multiplied by the 
11            contract price. The electric utility shall receive 
12            all renewable energy credits generated by the 
13            project during the first 15 years of operation, 
14            and retire all renewable energy credits paid for 
15            under this clause (3) and return at the end of the 
16            delivery term all geothermal renewable energy 
17            credits that were not paid for. Renewable energy 
18            credits generated by the project thereafter shall 
19            not be transferred under the renewable energy 
20            credit delivery contract with the counterparty 
21            electric utility.
22                (4) For renewable energy contracts for any 
23            type of community, shared, or similar geothermal 
24            heating and cooling system that operates using a 
25            subscription model and for which subscriptions are 
26            a basis for contractual payments, subscription of 
 
 
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1            90% of total renewable energy credit volumes or 
2            greater shall be deemed to be fully subscribed.
3                (5) Beginning with the long-term renewable 
4            resources procurement plan covering the delivery 
5            year beginning on June 1, 2030, the Agency may 
6            propose a payment structure for Program contracts 
7            upon a demonstration of qualification or need 
8            under criteria established by the Agency that is 
9            focused on supporting the small and emerging 
10            businesses and the businesses that most acutely 
11            face barriers to capital access. Successful 
12            applicant firms shall have advanced capital 
13            disbursed before renewable energy credits are 
14            first generated. The maximum amount or percentage 
15            of capital advanced shall be included in the 
16            long-term renewable resources procurement plan, 
17            and any amount actually advanced shall be designed 
18            to overcome the barriers in access to capital that 
19            are faced by an applicant through that applicant's 
20            demonstration of need. The amount or percentage of 
21            advanced capital may vary by year, or inter-year, 
22            by structure category, block, and other factors as 
23            deemed applicable by the Agency and by an 
24            applicant's demonstration of need. Contracts 
25            featuring capital advanced prior to system 
26            operation shall feature provisions to ensure both 
 
 
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1            the successful development of applicant projects 
2            and the delivery of renewable energy credits for 
3            the full term of the contract, including ongoing 
4            collateral requirements and other provisions 
5            deemed necessary by the Agency. The percentage or 
6            amount of capital advanced prior to system 
7            operation shall not increase the overall contract 
8            value.
9                (6) Each contract shall include provisions to 
10            ensure the delivery of the estimated quantity of 
11            geothermal renewable energy credits, including a 
12            requirement of performance assurance in an amount 
13            deemed appropriate by the Agency.
14                (7) An obligated utility shall be the 
15            counterparty to the contracts executed under this 
16            subparagraph (S) that are approved by the 
17            Commission. No contract shall be executed for an 
18            amount that is less than one geothermal renewable 
19            energy credit per year.
20                (8) Nothing in this subparagraph (S) shall 
21            require the utility to advance any payment or pay 
22            any amounts that exceed the actual amount of 
23            revenues anticipated to be collected by the 
24            utility inclusive of eligible funds collected in 
25            prior years and alternative compliance payments 
26            for use by the utility.
 
 
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1                (9) Contracts may be assignable, but only to 
2            entities first deemed by the Agency to have met 
3            Program terms and requirements applicable to 
4            direct Program participation. In developing 
5            contracts for the delivery of renewable energy 
6            credits from geothermal heating and cooling 
7            systems, the Agency may establish fees applicable 
8            to each contract assignment.
9                (10) If, at any time, approved applications 
10            for the Program exceed funds collected by the 
11            electric utility or would cause the Agency to 
12            exceed the limitation on the amount of renewable 
13            energy resources that may be procured, then the 
14            Agency may consider future uncommitted funds to be 
15            reserved for these contracts on a first-come, 
16            first-served basis.
17            (iv) In order to advance priority access to the 
18        clean energy economy for businesses and workers from 
19        communities that have been excluded from economic 
20        opportunities in the energy sector, been subject to 
21        disproportionate levels of pollution, and 
22        disproportionately experienced negative public health 
23        outcomes, the Agency shall apply its equity 
24        accountability system and minimum equity standards 
25        established under subsections (c-10), (c-15), (c-20), 
26        (c-25), and (c-30) to geothermal heating and cooling 
 
 
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1        system renewable energy credit procurement and 
2        programs and may include any proposed modifications to 
3        the equity accountability system and minimum equity 
4        standards that may be warranted with respect to 
5        geothermal heating and cooling systems in its plan 
6        submission to the Commission under Section 16-111.5 of 
7        the Public Utilities Act.
8            (v) Projects shall be developed in compliance with 
9        the prevailing wage and project labor agreement 
10        requirements, as applicable, for renewable energy 
11        projects in subparagraph (Q) of paragraph (1) of 
12        subsection (c). Projects approved under this Program 
13        are subject to the prevailing wage requirements 
14        outlined in subitem (x) of item (1) of subparagraph 
15        (Q) of paragraph (1) of this subsection (c). Renewable 
16        energy credits for any single geothermal heating and 
17        cooling project that is 142 tons or larger and is 
18        procured under this Program after the effective date 
19        of this amendatory Act of the 104th General Assembly 
20        shall only be eligible if the associated project was 
21        built by general contractors who entered into a 
22        project labor agreement prior to construction. The 
23        project labor agreement shall be filed with the 
24        Director in accordance with procedures established by 
25        the Agency through its long-term renewable resources 
26        procurement plan. The project labor agreement shall 
 
 
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1        provide the names, addresses, and occupations of the 
2        owner of the plant and the individuals representing 
3        the labor organization employees that participate in 
4        the project labor agreement. The project labor 
5        agreement shall also specify terms and conditions as 
6        provided in this Act.
7            (vi) The Agency shall strive to minimize 
8        administrative expenses in the implementation of the 
9        Program. The Agency may use any existing program 
10        administrator and any applicable subcontractors to 
11        develop, administer, implement, operate, and evaluate 
12        the Program.    
13        (T) Renewable energy credits procured under Agency 
14    procurements or programs for community solar projects with 
15    more than 3 megawatts in nameplate capacity must be 
16    procured from facilities built by general contractors 
17    that, prior to construction, enter into a project labor 
18    agreement, as defined by this Act, subject to the 
19    following requirements and limitations:
20            (i) The project labor agreement shall be filed 
21        with the Director in accordance with procedures 
22        established by the Agency through its long-term 
23        renewable resources procurement plan. Any information 
24        submitted to the Agency under this item (i) shall be 
25        considered commercially sensitive information.
26            (ii) At a minimum, the project labor agreement 
 
 
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1        must provide the names, addresses, and occupations of 
2        the owner of the project and any individuals 
3        representing the labor organization of the employees 
4        participating in the project labor agreement 
5        consistent with the Project Labor Agreements Act. The 
6        project labor agreement must also meet the terms and 
7        conditions, as set forth in this Act.
8            (iii) It is the intent of this Section to ensure 
9        that economic development occurs across communities in 
10        this State, that emerging businesses may grow, and 
11        that there is improved access to the clean energy 
12        economy by persons who have greater economic burdens 
13        to success. The Agency shall take into consideration 
14        the unique cost of compliance of this subparagraph (T) 
15        that may be borne by equity eligible contractors and 
16        shall include those costs when determining the price 
17        of renewable energy credits in the Adjustable Block 
18        program. The Agency shall consider costs associated 
19        with compliance, including in the development, 
20        financing, or construction of projects. The Agency 
21        shall periodically review the assumptions in these 
22        costs and may adjust prices in compliance with 
23        subparagraph (M) of this paragraph (1).    
24        (2) (Blank).
25        (3) (Blank). 
26        (4) The electric utility shall retire all renewable 
 
 
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1    energy credits used to comply with the standard.
2        (5) Beginning with the 2010 delivery year and ending 
3    June 1, 2017, an electric utility subject to this 
4    subsection (c) shall apply the lesser of the maximum 
5    alternative compliance payment rate or the most recent 
6    estimated alternative compliance payment rate for its 
7    service territory for the corresponding compliance period, 
8    established pursuant to subsection (d) of Section 16-115D 
9    of the Public Utilities Act to its retail customers that 
10    take service pursuant to the electric utility's hourly 
11    pricing tariff or tariffs. The electric utility shall 
12    retain all amounts collected as a result of the 
13    application of the alternative compliance payment rate or 
14    rates to such customers, and, beginning in 2011, the 
15    utility shall include in the information provided under 
16    item (1) of subsection (d) of Section 16-111.5 of the 
17    Public Utilities Act the amounts collected under the 
18    alternative compliance payment rate or rates for the prior 
19    year ending May 31. Notwithstanding any limitation on the 
20    procurement of renewable energy resources imposed by item 
21    (2) of this subsection (c), the Agency shall increase its 
22    spending on the purchase of renewable energy resources to 
23    be procured by the electric utility for the next plan year 
24    by an amount equal to the amounts collected by the utility 
25    under the alternative compliance payment rate or rates in 
26    the prior year ending May 31.
 
 
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1        (6) The electric utility shall be entitled to recover 
2    all of its costs associated with the procurement of 
3    renewable energy credits under plans approved under this 
4    Section and Section 16-111.5 of the Public Utilities Act. 
5    These costs shall include associated reasonable expenses 
6    for implementing the procurement programs, including, but 
7    not limited to, the costs of administering and evaluating 
8    the Adjustable Block program and the Geothermal Homes and 
9    Businesses Program, through an automatic adjustment clause 
10    tariff in accordance with subsection (k) of Section 16-108 
11    of the Public Utilities Act.
12        (7) Renewable energy credits procured from new 
13    photovoltaic projects or new distributed renewable energy 
14    generation devices under this Section after June 1, 2017 
15    (the effective date of Public Act 99-906) must be procured 
16    from devices installed by a qualified person in compliance 
17    with the requirements of Section 16-128A of the Public 
18    Utilities Act and any rules or regulations adopted 
19    thereunder.
20        In meeting the renewable energy requirements of this 
21    subsection (c), to the extent feasible and consistent with 
22    State and federal law, the renewable energy credit 
23    procurements, Adjustable Block solar program, and 
24    community renewable generation program shall provide 
25    employment opportunities for all segments of the 
26    population and workforce, including minority-owned and 
 
 
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1    female-owned business enterprises, and shall not, 
2    consistent with State and federal law, discriminate based 
3    on race or socioeconomic status.
4    (c-5) Procurement of renewable energy credits from new 
5renewable energy facilities installed at or adjacent to the 
6sites of electric generating facilities that burn or burned 
7coal as their primary fuel source.
8        (1) In addition to the procurement of renewable energy 
9    credits pursuant to long-term renewable resources 
10    procurement plans in accordance with subsection (c) of 
11    this Section and Section 16-111.5 of the Public Utilities 
12    Act, the Agency shall conduct procurement events in 
13    accordance with this subsection (c-5) for the procurement 
14    by electric utilities that served more than 300,000 retail 
15    customers in this State as of January 1, 2019 of renewable 
16    energy credits from new renewable energy facilities to be 
17    installed at or adjacent to the sites of electric 
18    generating facilities that, as of January 1, 2016, burned 
19    coal as their primary fuel source and meet the other 
20    criteria specified in this subsection (c-5). For purposes 
21    of this subsection (c-5), "new renewable energy facility" 
22    means a new utility-scale solar project as defined in this 
23    Section 1-75. The renewable energy credits procured 
24    pursuant to this subsection (c-5) may be included or 
25    counted for purposes of compliance with the amounts of 
26    renewable energy credits required to be procured pursuant 
 
 
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1    to subsection (c) of this Section to the extent that there 
2    are otherwise shortfalls in compliance with such 
3    requirements. The procurement of renewable energy credits 
4    by electric utilities pursuant to this subsection (c-5) 
5    shall be funded solely by revenues collected from the Coal 
6    to Solar and Energy Storage Initiative Charge provided for 
7    in this subsection (c-5) and subsection (i-5) of Section 
8    16-108 of the Public Utilities Act, shall not be funded by 
9    revenues collected through any of the other funding 
10    mechanisms provided for in subsection (c) of this Section, 
11    and shall not be subject to the limitation imposed by 
12    subsection (c) on charges to retail customers for costs to 
13    procure renewable energy resources pursuant to subsection 
14    (c), and shall not be subject to any other requirements or 
15    limitations of subsection (c).
16        (2) The Agency shall conduct 2 procurement events to 
17    select owners of electric generating facilities meeting 
18    the eligibility criteria specified in this subsection 
19    (c-5) to enter into long-term contracts to sell renewable 
20    energy credits to electric utilities serving more than 
21    300,000 retail customers in this State as of January 1, 
22    2019. The first procurement event shall be conducted no 
23    later than March 31, 2022, unless the Agency elects to 
24    delay it, until no later than May 1, 2022, due to its 
25    overall volume of work, and shall be to select owners of 
26    electric generating facilities located in this State and 
 
 
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1    south of federal Interstate Highway 80 that meet the 
2    eligibility criteria specified in this subsection (c-5). 
3    The second procurement event shall be conducted no sooner 
4    than September 30, 2022 and no later than October 31, 2022 
5    and shall be to select owners of electric generating 
6    facilities located anywhere in this State that meet the 
7    eligibility criteria specified in this subsection (c-5). 
8    The Agency shall establish and announce a time period, 
9    which shall begin no later than 30 days prior to the 
10    scheduled date for the procurement event, during which 
11    applicants may submit applications to be selected as 
12    suppliers of renewable energy credits pursuant to this 
13    subsection (c-5). The eligibility criteria for selection 
14    as a supplier of renewable energy credits pursuant to this 
15    subsection (c-5) shall be as follows:
16            (A) The applicant owns an electric generating 
17        facility located in this State that: (i) as of January 
18        1, 2016, burned coal as its primary fuel to generate 
19        electricity; and (ii) has, or had prior to retirement, 
20        an electric generating capacity of at least 150 
21        megawatts. The electric generating facility can be 
22        either: (i) retired as of the date of the procurement 
23        event; or (ii) still operating as of the date of the 
24        procurement event.
25            (B) The applicant is not (i) an electric 
26        cooperative as defined in Section 3-119 of the Public 
 
 
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1        Utilities Act, or (ii) an entity described in 
2        subsection (b)(1) of Section 3-105 of the Public 
3        Utilities Act, or an association or consortium of or 
4        an entity owned by entities described in (i) or (ii); 
5        and the coal-fueled electric generating facility was 
6        at one time owned, in whole or in part, by a public 
7        utility as defined in Section 3-105 of the Public 
8        Utilities Act.
9            (C) If participating in the first procurement 
10        event, the applicant proposes and commits to construct 
11        and operate, at the site, and if necessary for 
12        sufficient space on property adjacent to the existing 
13        property, at which the electric generating facility 
14        identified in paragraph (A) is located: (i) a new 
15        renewable energy facility of at least 20 megawatts but 
16        no more than 100 megawatts of electric generating 
17        capacity, and (ii) an energy storage facility having a 
18        storage capacity equal to at least 2 megawatts and at 
19        most 10 megawatts. If participating in the second 
20        procurement event, the applicant proposes and commits 
21        to construct and operate, at the site, and if 
22        necessary for sufficient space on property adjacent to 
23        the existing property, at which the electric 
24        generating facility identified in paragraph (A) is 
25        located: (i) a new renewable energy facility of at 
26        least 5 megawatts but no more than 20 megawatts of 
 
 
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1        electric generating capacity, and (ii) an energy 
2        storage facility having a storage capacity equal to at 
3        least 0.5 megawatts and at most one megawatt.
4            (D) The applicant agrees that the new renewable 
5        energy facility and the energy storage facility will 
6        be constructed or installed by a qualified entity or 
7        entities in compliance with the requirements of 
8        subsection (g) of Section 16-128A of the Public 
9        Utilities Act and any rules adopted thereunder.
10            (E) The applicant agrees that personnel operating 
11        the new renewable energy facility and the energy 
12        storage facility will have the requisite skills, 
13        knowledge, training, experience, and competence, which 
14        may be demonstrated by completion or current 
15        participation and ultimate completion by employees of 
16        an accredited or otherwise recognized apprenticeship 
17        program for the employee's particular craft, trade, or 
18        skill, including through training and education 
19        courses and opportunities offered by the owner to 
20        employees of the coal-fueled electric generating 
21        facility or by previous employment experience 
22        performing the employee's particular work skill or 
23        function.
24            (F) The applicant commits that not less than the 
25        prevailing wage, as determined pursuant to the 
26        Prevailing Wage Act, will be paid to the applicant's 
 
 
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1        employees engaged in construction activities 
2        associated with the new renewable energy facility and 
3        the new energy storage facility and to the employees 
4        of applicant's contractors engaged in construction 
5        activities associated with the new renewable energy 
6        facility and the new energy storage facility, and 
7        that, on or before the commercial operation date of 
8        the new renewable energy facility, the applicant shall 
9        file a report with the Agency certifying that the 
10        requirements of this subparagraph (F) have been met.
11            (G) The applicant commits that if selected, it 
12        will negotiate a project labor agreement for the 
13        construction of the new renewable energy facility and 
14        associated energy storage facility that includes 
15        provisions requiring the parties to the agreement to 
16        work together to establish diversity threshold 
17        requirements and to ensure best efforts to meet 
18        diversity targets, improve diversity at the applicable 
19        job site, create diverse apprenticeship opportunities, 
20        and create opportunities to employ former coal-fired 
21        power plant workers.
22            (H) The applicant commits to enter into a contract 
23        or contracts for the applicable duration to provide 
24        specified numbers of renewable energy credits each 
25        year from the new renewable energy facility to 
26        electric utilities that served more than 300,000 
 
 
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1        retail customers in this State as of January 1, 2019, 
2        at a price of $30 per renewable energy credit. The 
3        price per renewable energy credit shall be fixed at 
4        $30 for the applicable duration and the renewable 
5        energy credits shall not be indexed renewable energy 
6        credits as provided for in item (v) of subparagraph 
7        (G) of paragraph (1) of subsection (c) of Section 1-75 
8        of this Act. The applicable duration of each contract 
9        shall be 20 years, unless the applicant is physically 
10        interconnected to the PJM Interconnection, LLC 
11        transmission grid and had a generating capacity of at 
12        least 1,200 megawatts as of January 1, 2021, in which 
13        case the applicable duration of the contract shall be 
14        15 years.
15            (I) The applicant's application is certified by an 
16        officer of the applicant and by an officer of the 
17        applicant's ultimate parent company, if any.
18        (3) An applicant may submit applications to contract 
19    to supply renewable energy credits from more than one new 
20    renewable energy facility to be constructed at or adjacent 
21    to one or more qualifying electric generating facilities 
22    owned by the applicant. The Agency may select new 
23    renewable energy facilities to be located at or adjacent 
24    to the sites of more than one qualifying electric 
25    generation facility owned by an applicant to contract with 
26    electric utilities to supply renewable energy credits from 
 
 
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1    such facilities.
2        (4) The Agency shall assess fees to each applicant to 
3    recover the Agency's costs incurred in receiving and 
4    evaluating applications, conducting the procurement event, 
5    developing contracts for sale, delivery and purchase of 
6    renewable energy credits, and monitoring the 
7    administration of such contracts, as provided for in this 
8    subsection (c-5), including fees paid to a procurement 
9    administrator retained by the Agency for one or more of 
10    these purposes.
11        (5) The Agency shall select the applicants and the new 
12    renewable energy facilities to contract with electric 
13    utilities to supply renewable energy credits in accordance 
14    with this subsection (c-5). In the first procurement 
15    event, the Agency shall select applicants and new 
16    renewable energy facilities to supply renewable energy 
17    credits, at a price of $30 per renewable energy credit, 
18    aggregating to no less than 400,000 renewable energy 
19    credits per year for the applicable duration, assuming 
20    sufficient qualifying applications to supply, in the 
21    aggregate, at least that amount of renewable energy 
22    credits per year; and not more than 580,000 renewable 
23    energy credits per year for the applicable duration. In 
24    the second procurement event, the Agency shall select 
25    applicants and new renewable energy facilities to supply 
26    renewable energy credits, at a price of $30 per renewable 
 
 
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1    energy credit, aggregating to no more than 625,000 
2    renewable energy credits per year less the amount of 
3    renewable energy credits each year contracted for as a 
4    result of the first procurement event, for the applicable 
5    durations. The number of renewable energy credits to be 
6    procured as specified in this paragraph (5) shall not be 
7    reduced based on renewable energy credits procured in the 
8    self-direct renewable energy credit compliance program 
9    established pursuant to subparagraph (R) of paragraph (1) 
10    of subsection (c) of Section 1-75.
11        (6) The obligation to purchase renewable energy 
12    credits from the applicants and their new renewable energy 
13    facilities selected by the Agency shall be allocated to 
14    the electric utilities based on their respective 
15    percentages of kilowatthours delivered to delivery 
16    services customers to the aggregate kilowatthour 
17    deliveries by the electric utilities to delivery services 
18    customers for the year ended December 31, 2021. In order 
19    to achieve these allocation percentages between or among 
20    the electric utilities, the Agency shall require each 
21    applicant that is selected in the procurement event to 
22    enter into a contract with each electric utility for the 
23    sale and purchase of renewable energy credits from each 
24    new renewable energy facility to be constructed and 
25    operated by the applicant, with the sale and purchase 
26    obligations under the contracts to aggregate to the total 
 
 
10400SB0025ham004- 320 -LRB104 16098 AAS 29398 a

1    number of renewable energy credits per year to be supplied 
2    by the applicant from the new renewable energy facility.
3        (7) The Agency shall submit its proposed selection of 
4    applicants, new renewable energy facilities to be 
5    constructed, and renewable energy credit amounts for each 
6    procurement event to the Commission for approval. The 
7    Commission shall, within 2 business days after receipt of 
8    the Agency's proposed selections, approve the proposed 
9    selections if it determines that the applicants and the 
10    new renewable energy facilities to be constructed meet the 
11    selection criteria set forth in this subsection (c-5) and 
12    that the Agency seeks approval for contracts of applicable 
13    durations aggregating to no more than the maximum amount 
14    of renewable energy credits per year authorized by this 
15    subsection (c-5) for the procurement event, at a price of 
16    $30 per renewable energy credit.
17        (8) The Agency, in conjunction with its procurement 
18    administrator if one is retained, the electric utilities, 
19    and potential applicants for contracts to produce and 
20    supply renewable energy credits pursuant to this 
21    subsection (c-5), shall develop a standard form contract 
22    for the sale, delivery and purchase of renewable energy 
23    credits pursuant to this subsection (c-5). Each contract 
24    resulting from the first procurement event shall allow for 
25    a commercial operation date for the new renewable energy 
26    facility of either June 1, 2023 or June 1, 2024, with such 
 
 
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1    dates subject to adjustment as provided in this paragraph. 
2    Each contract resulting from the second procurement event 
3    shall provide for a commercial operation date on June 1 
4    next occurring up to 48 months after execution of the 
5    contract. Each contract shall provide that the owner shall 
6    receive payments for renewable energy credits for the 
7    applicable durations beginning with the commercial 
8    operation date of the new renewable energy facility. The 
9    form contract shall provide for adjustments to the 
10    commercial operation and payment start dates as needed due 
11    to any delays in completing the procurement and 
12    contracting processes, in finalizing interconnection 
13    agreements and installing interconnection facilities, and 
14    in obtaining other necessary governmental permits and 
15    approvals. The form contract shall be, to the maximum 
16    extent possible, consistent with standard electric 
17    industry contracts for sale, delivery, and purchase of 
18    renewable energy credits while taking into account the 
19    specific requirements of this subsection (c-5). The form 
20    contract shall provide for over-delivery and 
21    under-delivery of renewable energy credits within 
22    reasonable ranges during each 12-month period and penalty, 
23    default, and enforcement provisions for failure of the 
24    selling party to deliver renewable energy credits as 
25    specified in the contract and to comply with the 
26    requirements of this subsection (c-5). The standard form 
 
 
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1    contract shall specify that all renewable energy credits 
2    delivered to the electric utility pursuant to the contract 
3    shall be retired. The Agency shall make the proposed 
4    contracts available for a reasonable period for comment by 
5    potential applicants, and shall publish the final form 
6    contract at least 30 days before the date of the first 
7    procurement event.
8        (9) Coal to Solar and Energy Storage Initiative 
9    Charge.
10            (A) By no later than July 1, 2022, each electric 
11        utility that served more than 300,000 retail customers 
12        in this State as of January 1, 2019 shall file a tariff 
13        with the Commission for the billing and collection of 
14        a Coal to Solar and Energy Storage Initiative Charge 
15        in accordance with subsection (i-5) of Section 16-108 
16        of the Public Utilities Act, with such tariff to be 
17        effective, following review and approval or 
18        modification by the Commission, beginning January 1, 
19        2023. The tariff shall provide for the calculation and 
20        setting of the electric utility's Coal to Solar and 
21        Energy Storage Initiative Charge to collect revenues 
22        estimated to be sufficient, in the aggregate, (i) to 
23        enable the electric utility to pay for the renewable 
24        energy credits it has contracted to purchase in the 
25        delivery year beginning June 1, 2023 and each delivery 
26        year thereafter from new renewable energy facilities 
 
 
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1        located at the sites of qualifying electric generating 
2        facilities, and (ii) to fund the grant payments to be 
3        made in each delivery year by the Department of 
4        Commerce and Economic Opportunity, or any successor 
5        department or agency, which shall be referred to in 
6        this subsection (c-5) as the Department, pursuant to 
7        paragraph (10) of this subsection (c-5). The electric 
8        utility's tariff shall provide for the billing and 
9        collection of the Coal to Solar and Energy Storage 
10        Initiative Charge on each kilowatthour of electricity 
11        delivered to its delivery services customers within 
12        its service territory and shall provide for an annual 
13        reconciliation of revenues collected with actual 
14        costs, in accordance with subsection (i-5) of Section 
15        16-108 of the Public Utilities Act.
16            (B) Each electric utility shall remit on a monthly 
17        basis to the State Treasurer, for deposit in the Coal 
18        to Solar and Energy Storage Initiative Fund provided 
19        for in this subsection (c-5), the electric utility's 
20        collections of the Coal to Solar and Energy Storage 
21        Initiative Charge in the amount estimated to be needed 
22        by the Department for grant payments pursuant to grant 
23        contracts entered into by the Department pursuant to 
24        paragraph (10) of this subsection (c-5).
25        (10) Coal to Solar and Energy Storage Initiative Fund.
26            (A) The Coal to Solar and Energy Storage 
 
 
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1        Initiative Fund is established as a special fund in 
2        the State treasury. The Coal to Solar and Energy 
3        Storage Initiative Fund is authorized to receive, by 
4        statutory deposit, that portion specified in item (B) 
5        of paragraph (9) of this subsection (c-5) of moneys 
6        collected by electric utilities through imposition of 
7        the Coal to Solar and Energy Storage Initiative Charge 
8        required by this subsection (c-5). The Coal to Solar 
9        and Energy Storage Initiative Fund shall be 
10        administered by the Department to provide grants to 
11        support the installation and operation of energy 
12        storage facilities at the sites of qualifying electric 
13        generating facilities meeting the criteria specified 
14        in this paragraph (10).
15            (B) The Coal to Solar and Energy Storage 
16        Initiative Fund shall not be subject to sweeps, 
17        administrative charges, or chargebacks, including, but 
18        not limited to, those authorized under Section 8h of 
19        the State Finance Act, that would in any way result in 
20        the transfer of those funds from the Coal to Solar and 
21        Energy Storage Initiative Fund to any other fund of 
22        this State or in having any such funds utilized for any 
23        purpose other than the express purposes set forth in 
24        this paragraph (10).
25            (C) The Department shall utilize up to 
26        $280,500,000 in the Coal to Solar and Energy Storage 
 
 
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1        Initiative Fund for grants, assuming sufficient 
2        qualifying applicants, to support installation of 
3        energy storage facilities at the sites of up to 3 
4        qualifying electric generating facilities located in 
5        the Midcontinent Independent System Operator, Inc., 
6        region in Illinois and the sites of up to 2 qualifying 
7        electric generating facilities located in the PJM 
8        Interconnection, LLC region in Illinois that meet the 
9        criteria set forth in this subparagraph (C). The 
10        criteria for receipt of a grant pursuant to this 
11        subparagraph (C) are as follows:
12                (1) the electric generating facility at the 
13            site has, or had prior to retirement, an electric 
14            generating capacity of at least 150 megawatts;
15                (2) the electric generating facility burns (or 
16            burned prior to retirement) coal as its primary 
17            source of fuel;
18                (3) if the electric generating facility is 
19            retired, it was retired subsequent to January 1, 
20            2016;
21                (4) the owner of the electric generating 
22            facility has not been selected by the Agency 
23            pursuant to this subsection (c-5) of this Section 
24            to enter into a contract to sell renewable energy 
25            credits to one or more electric utilities from a 
26            new renewable energy facility located or to be 
 
 
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1            located at or adjacent to the site at which the 
2            electric generating facility is located;
3                (5) the electric generating facility located 
4            at the site was at one time owned, in whole or in 
5            part, by a public utility as defined in Section 
6            3-105 of the Public Utilities Act;
7                (6) the electric generating facility at the 
8            site is not owned by (i) an electric cooperative 
9            as defined in Section 3-119 of the Public 
10            Utilities Act, or (ii) an entity described in 
11            subsection (b)(1) of Section 3-105 of the Public 
12            Utilities Act, or an association or consortium of 
13            or an entity owned by entities described in items 
14            (i) or (ii);
15                (7) the proposed energy storage facility at 
16            the site will have energy storage capacity of at 
17            least 37 megawatts;
18                (8) the owner commits to place the energy 
19            storage facility into commercial operation on 
20            either June 1, 2023, June 1, 2024, or June 1, 2025, 
21            with such date subject to adjustment as needed due 
22            to any delays in completing the grant contracting 
23            process, in finalizing interconnection agreements 
24            and in installing interconnection facilities, and 
25            in obtaining necessary governmental permits and 
26            approvals;
 
 
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1                (9) the owner agrees that the new energy 
2            storage facility will be constructed or installed 
3            by a qualified entity or entities consistent with 
4            the requirements of subsection (g) of Section 
5            16-128A of the Public Utilities Act and any rules 
6            adopted under that Section;
7                (10) the owner agrees that personnel operating 
8            the energy storage facility will have the 
9            requisite skills, knowledge, training, experience, 
10            and competence, which may be demonstrated by 
11            completion or current participation and ultimate 
12            completion by employees of an accredited or 
13            otherwise recognized apprenticeship program for 
14            the employee's particular craft, trade, or skill, 
15            including through training and education courses 
16            and opportunities offered by the owner to 
17            employees of the coal-fueled electric generating 
18            facility or by previous employment experience 
19            performing the employee's particular work skill or 
20            function;
21                (11) the owner commits that not less than the 
22            prevailing wage, as determined pursuant to the 
23            Prevailing Wage Act, will be paid to the owner's 
24            employees engaged in construction activities 
25            associated with the new energy storage facility 
26            and to the employees of the owner's contractors 
 
 
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1            engaged in construction activities associated with 
2            the new energy storage facility, and that, on or 
3            before the commercial operation date of the new 
4            energy storage facility, the owner shall file a 
5            report with the Department certifying that the 
6            requirements of this subparagraph (11) have been 
7            met; and
8                (12) the owner commits that if selected to 
9            receive a grant, it will negotiate a project labor 
10            agreement for the construction of the new energy 
11            storage facility that includes provisions 
12            requiring the parties to the agreement to work 
13            together to establish diversity threshold 
14            requirements and to ensure best efforts to meet 
15            diversity targets, improve diversity at the 
16            applicable job site, create diverse apprenticeship 
17            opportunities, and create opportunities to employ 
18            former coal-fired power plant workers.
19            The Department shall accept applications for this 
20        grant program until March 31, 2022 and shall announce 
21        the award of grants no later than June 1, 2022. The 
22        Department shall make the grant payments to a 
23        recipient in equal annual amounts for 10 years 
24        following the date the energy storage facility is 
25        placed into commercial operation. The annual grant 
26        payments to a qualifying energy storage facility shall 
 
 
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1        be $110,000 per megawatt of energy storage capacity, 
2        with total annual grant payments pursuant to this 
3        subparagraph (C) for qualifying energy storage 
4        facilities not to exceed $28,050,000 in any year.
5            (D) Grants of funding for energy storage 
6        facilities pursuant to subparagraph (C) of this 
7        paragraph (10), from the Coal to Solar and Energy 
8        Storage Initiative Fund, shall be memorialized in 
9        grant contracts between the Department and the 
10        recipient. The grant contracts shall specify the date 
11        or dates in each year on which the annual grant 
12        payments shall be paid.
13            (E) All disbursements from the Coal to Solar and 
14        Energy Storage Initiative Fund shall be made only upon 
15        warrants of the Comptroller drawn upon the Treasurer 
16        as custodian of the Fund upon vouchers signed by the 
17        Director of the Department or by the person or persons 
18        designated by the Director of the Department for that 
19        purpose. The Comptroller is authorized to draw the 
20        warrants upon vouchers so signed. The Treasurer shall 
21        accept all written warrants so signed and shall be 
22        released from liability for all payments made on those 
23        warrants.
24        (11) Diversity, equity, and inclusion plans.
25            (A) Each applicant selected in a procurement event 
26        to contract to supply renewable energy credits in 
 
 
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1        accordance with this subsection (c-5) and each owner 
2        selected by the Department to receive a grant or 
3        grants to support the construction and operation of a 
4        new energy storage facility or facilities in 
5        accordance with this subsection (c-5) shall, within 60 
6        days following the Commission's approval of the 
7        applicant to contract to supply renewable energy 
8        credits or within 60 days following execution of a 
9        grant contract with the Department, as applicable, 
10        submit to the Commission a diversity, equity, and 
11        inclusion plan setting forth the applicant's or 
12        owner's numeric goals for the diversity composition of 
13        its supplier entities for the new renewable energy 
14        facility or new energy storage facility, as 
15        applicable, which shall be referred to for purposes of 
16        this paragraph (11) as the project, and the 
17        applicant's or owner's action plan and schedule for 
18        achieving those goals.
19            (B) For purposes of this paragraph (11), diversity 
20        composition shall be based on the percentage, which 
21        shall be a minimum of 25%, of eligible expenditures 
22        for contract awards for materials and services (which 
23        shall be defined in the plan) to business enterprises 
24        owned by minority persons, women, or persons with 
25        disabilities as defined in Section 2 of the Business 
26        Enterprise for Minorities, Women, and Persons with 
 
 
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1        Disabilities Act, to LGBTQ business enterprises, to 
2        veteran-owned business enterprises, and to business 
3        enterprises located in environmental justice 
4        communities. The diversity composition goals of the 
5        plan may include eligible expenditures in areas for 
6        vendor or supplier opportunities in addition to 
7        development and construction of the project, and may 
8        exclude from eligible expenditures materials and 
9        services with limited market availability, limited 
10        production and availability from suppliers in the 
11        United States, such as solar panels and storage 
12        batteries, and material and services that are subject 
13        to critical energy infrastructure or cybersecurity 
14        requirements or restrictions. The plan may provide 
15        that the diversity composition goals may be met 
16        through Tier 1 Direct or Tier 2 subcontracting 
17        expenditures or a combination thereof for the project.
18            (C) The plan shall provide for, but not be limited 
19        to: (i) internal initiatives, including multi-tier 
20        initiatives, by the applicant or owner, or by its 
21        engineering, procurement and construction contractor 
22        if one is used for the project, which for purposes of 
23        this paragraph (11) shall be referred to as the EPC 
24        contractor, to enable diverse businesses to be 
25        considered fairly for selection to provide materials 
26        and services; (ii) requirements for the applicant or 
 
 
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1        owner or its EPC contractor to proactively solicit and 
2        utilize diverse businesses to provide materials and 
3        services; and (iii) requirements for the applicant or 
4        owner or its EPC contractor to hire a diverse 
5        workforce for the project. The plan shall include a 
6        description of the applicant's or owner's diversity 
7        recruiting efforts both for the project and for other 
8        areas of the applicant's or owner's business 
9        operations. The plan shall provide for the imposition 
10        of financial penalties on the applicant's or owner's 
11        EPC contractor for failure to exercise best efforts to 
12        comply with and execute the EPC contractor's diversity 
13        obligations under the plan. The plan may provide for 
14        the applicant or owner to set aside a portion of the 
15        work on the project to serve as an incubation program 
16        for qualified businesses, as specified in the plan, 
17        owned by minority persons, women, persons with 
18        disabilities, LGBTQ persons, and veterans, and 
19        businesses located in environmental justice 
20        communities, seeking to enter the renewable energy 
21        industry.
22            (D) The applicant or owner may submit a revised or 
23        updated plan to the Commission from time to time as 
24        circumstances warrant. The applicant or owner shall 
25        file annual reports with the Commission detailing the 
26        applicant's or owner's progress in implementing its 
 
 
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1        plan and achieving its goals and any modifications the 
2        applicant or owner has made to its plan to better 
3        achieve its diversity, equity and inclusion goals. The 
4        applicant or owner shall file a final report on the 
5        fifth June 1 following the commercial operation date 
6        of the new renewable energy resource or new energy 
7        storage facility, but the applicant or owner shall 
8        thereafter continue to be subject to applicable 
9        reporting requirements of Section 5-117 of the Public 
10        Utilities Act. 
11    (c-10) Equity accountability system. It is the purpose of 
12this subsection (c-10) to create an equity accountability 
13system, which includes the minimum equity standards for all 
14renewable energy procurements, the equity category of the 
15Adjustable Block Program, and the equity prioritization for 
16noncompetitive procurements, that is successful in advancing 
17priority access to the clean energy economy for businesses and 
18workers from communities that have been excluded from economic 
19opportunities in the energy sector, have been subject to 
20disproportionate levels of pollution, and have 
21disproportionately experienced negative public health 
22outcomes. Further, it is the purpose of this subsection to 
23ensure that this equity accountability system is successful in 
24advancing equity across Illinois by providing access to the 
25clean energy economy for businesses and workers from 
26communities that have been historically excluded from economic 
 
 
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1opportunities in the energy sector, have been subject to 
2disproportionate levels of pollution, and have 
3disproportionately experienced negative public health 
4outcomes.
5        (1) Minimum equity standards. The Agency shall create 
6    programs with the purpose of increasing access to and 
7    development of equity eligible contractors, who are prime 
8    contractors and subcontractors, across all of the programs 
9    it manages. All applications for renewable energy credit 
10    procurements shall comply with specific minimum equity 
11    commitments. Starting in the delivery year immediately 
12    following the next long-term renewable resources 
13    procurement plan, at least 10% of the project workforce 
14    for each entity participating in a procurement program 
15    outlined in this subsection (c-10) must be done by equity 
16    eligible persons or equity eligible contractors. The 
17    Agency shall increase the minimum percentage each delivery 
18    year thereafter by increments that ensure a statewide 
19    average of 30% of the project workforce for each entity 
20    participating in a procurement program is done by equity 
21    eligible persons or equity eligible contractors by 2030. 
22    The Agency shall propose a schedule of percentage 
23    increases to the minimum equity standards in its draft 
24    revised renewable energy resources procurement plan 
25    submitted to the Commission for approval pursuant to 
26    paragraph (5) of subsection (b) of Section 16-111.5 of the 
 
 
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1    Public Utilities Act. In determining these annual 
2    increases, the Agency shall have the discretion to 
3    establish different minimum equity standards for different 
4    types of procurements and different regions of the State 
5    if the Agency finds that doing so will further the 
6    purposes of this subsection (c-10). The proposed schedule 
7    of annual increases shall be revisited and updated on an 
8    annual basis. Revisions shall be developed with 
9    stakeholder input, including from equity eligible persons, 
10    equity eligible contractors, clean energy industry 
11    representatives, and community-based organizations that 
12    work with such persons and contractors.
13            (A) At the start of each delivery year, the Agency 
14        shall require a compliance plan from each entity 
15        participating in a procurement program of subsection 
16        (c) of this Section, and entities opting to comply 
17        with the minimum equity standard through the Illinois 
18        Solar for All Program under Section 1-56 of this Act,    
19        that demonstrates how they will achieve compliance 
20        with the minimum equity standard percentage for work 
21        completed in that delivery year. If an entity applies 
22        for its approved vendor or designee status between 
23        delivery years, the Agency shall require a compliance 
24        plan at the time of application.
25            (B) Halfway through each delivery year, the Agency 
26        shall require each entity participating in a 
 
 
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1        procurement program to confirm that it will achieve 
2        compliance in that delivery year, when applicable. The 
3        Agency may offer corrective action plans to entities 
4        that are not on track to achieve compliance.
5            (C) At the end of each delivery year, each entity 
6        participating and completing work in that delivery 
7        year in a procurement program of subsection (c) shall 
8        submit a report to the Agency that demonstrates how it 
9        achieved compliance with the minimum equity standards 
10        percentage for that delivery year.
11            (D) The Agency shall prohibit participation in 
12        procurement programs by an approved vendor or 
13        designee, as applicable, or entities with which an 
14        approved vendor or designee, as applicable, shares a 
15        common parent company if an approved vendor or 
16        designee, as applicable, failed to meet the minimum 
17        equity standards for the prior delivery year. Waivers 
18        approved for lack of equity eligible persons or equity 
19        eligible contractors in a geographic area of a project 
20        shall not count against the approved vendor or 
21        designee. The Agency shall offer a corrective action 
22        plan for any such entities to assist them in obtaining 
23        compliance and shall allow continued access to 
24        procurement programs upon an approved vendor or 
25        designee demonstrating compliance.
26            (E) The Agency shall pursue efficiencies achieved 
 
 
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1        by combining with other approved vendor or designee 
2        reporting.
3        (2) Equity accountability system within the Adjustable 
4    Block program. The equity category described in item (vi) 
5    of subparagraph (K) of subsection (c) is only available to 
6    applicants that are equity eligible contractors.
7        (3) Equity accountability system within competitive 
8    procurements. Through its long-term renewable resources 
9    procurement plan, the Agency shall develop requirements 
10    for ensuring that competitive procurement processes, 
11    including utility-scale solar, utility-scale wind, and 
12    brownfield site photovoltaic projects, advance the equity 
13    goals of this subsection (c-10). Subject to Commission 
14    approval, the Agency shall develop bid application 
15    requirements and a bid evaluation methodology for ensuring 
16    that utilization of equity eligible contractors, whether 
17    as bidders or as participants on project development, is 
18    optimized, including requiring that winning or successful 
19    applicants for utility-scale projects are or will partner 
20    with equity eligible contractors and giving preference to 
21    bids through which a higher portion of contract value 
22    flows to equity eligible contractors. To the extent 
23    practicable, entities participating in competitive 
24    procurements shall also be required to meet all the equity 
25    accountability requirements for approved vendors and their 
26    designees under this subsection (c-10). In developing 
 
 
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1    these requirements, the Agency shall also consider whether 
2    equity goals can be further advanced through additional 
3    measures.
4        (4) In the first revision to the long-term renewable 
5    energy resources procurement plan and each revision 
6    thereafter, the Agency shall include the following:
7            (A) The current status and number of equity 
8        eligible contractors listed in the Energy Workforce 
9        Equity Database designed in subsection (c-25), 
10        including the number of equity eligible contractors 
11        with current certifications as issued by the Agency.
12            (B) A mechanism for measuring, tracking, and 
13        reporting project workforce at the approved vendor or 
14        designee level, as applicable, which shall include a 
15        measurement methodology and records to be made 
16        available for audit by the Agency or the Program 
17        Administrator.
18            (C) A program for approved vendors, designees, 
19        eligible persons, and equity eligible contractors to 
20        receive trainings, guidance, and other support from 
21        the Agency or its designee regarding the equity 
22        category outlined in item (vi) of subparagraph (K) of 
23        paragraph (1) of subsection (c) and in meeting the 
24        minimum equity standards of this subsection (c-10).
25            (D) A process for certifying equity eligible 
26        contractors and equity eligible persons. The 
 
 
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1        certification process shall coordinate with the Energy 
2        Workforce Equity Database set forth in subsection 
3        (c-25).
4            (E) An application for waiver of the minimum 
5        equity standards of this subsection, which the Agency 
6        shall have the discretion to grant in rare 
7        circumstances. The Agency may grant such a waiver 
8        where the applicant provides evidence of significant 
9        efforts toward meeting the minimum equity commitment, 
10        including: use of the Energy Workforce Equity 
11        Database; efforts to hire or contract with entities 
12        that hire eligible persons; and efforts to establish 
13        contracting relationships with eligible contractors. 
14        The Agency shall support applicants in understanding 
15        the Energy Workforce Equity Database and other 
16        resources for pursuing compliance of the minimum 
17        equity standards. Waivers shall be project-specific, 
18        unless the Agency deems it necessary to grant a waiver 
19        across a portfolio of projects, and in effect for no 
20        longer than one year. Any waiver extension or 
21        subsequent waiver request from an applicant shall be 
22        subject to the requirements of this Section and shall 
23        specify efforts made to reach compliance. When 
24        considering whether to grant a waiver, and to what 
25        extent, the Agency shall consider the degree to which 
26        similarly situated applicants have been able to meet 
 
 
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1        these minimum equity commitments. For repeated waiver 
2        requests for specific lack of eligible persons or 
3        eligible contractors available, the Agency shall make 
4        recommendations to target recruitment to add such 
5        eligible persons or eligible contractors to the 
6        database.
7        (5) The Agency shall collect information about work on 
8    projects or portfolios of projects subject to these 
9    minimum equity standards to ensure compliance with this 
10    subsection (c-10). Reporting in furtherance of this 
11    requirement may be combined with other annual reporting 
12    requirements. Such reporting shall include proof of 
13    certification of each equity eligible contractor or equity 
14    eligible person during the applicable time period.
15        As part of the reporting requirement under this 
16    subparagraph (5), the Agency shall collect and report 
17    information about the use of equity eligible contractors 
18    and equity eligible persons, as well as Minimum Equity 
19    Standard compliance and waiver usage on the Adjustable 
20    Block program and utility-scale projects subject to 
21    project labor agreements. The Agency shall note any 
22    instances of the projects being unable to meet or 
23    requiring a waiver to meet Minimum Equity Standard 
24    requirements and the location of those projects.
25        On an annual basis, the Agency shall submit a written 
26    summary of its findings on an annual basis to the General 
 
 
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1    Assembly and the Governor and shall make the report and 
2    summary available on the Agency's website.
3        (6) The Agency shall keep confidential all information 
4    and communication that provides private or personal 
5    information.
6        (7) Modifications to the equity accountability system. 
7    As part of the update of the long-term renewable resources 
8    procurement plan to be initiated in 2023, or sooner if the 
9    Agency deems necessary, the Agency shall determine the 
10    extent to which the equity accountability system described 
11    in this subsection (c-10) has advanced the goals of this 
12    amendatory Act of the 102nd General Assembly, including 
13    through the inclusion of equity eligible persons and 
14    equity eligible contractors in renewable energy credit 
15    projects. If the Agency finds that the equity 
16    accountability system has failed to meet those goals to 
17    its fullest potential, the Agency may revise the following 
18    criteria for future Agency procurements: (A) the 
19    percentage of project workforce, or other appropriate 
20    workforce measure, certified as equity eligible persons or 
21    equity eligible contractors; (B) definitions for equity 
22    investment eligible persons and equity investment eligible 
23    community; and (C) such other modifications necessary to 
24    advance the goals of this amendatory Act of the 102nd 
25    General Assembly effectively. Such revised criteria may 
26    also establish distinct equity accountability systems for 
 
 
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1    different types of procurements or different regions of 
2    the State if the Agency finds that doing so will further 
3    the purposes of such programs. Revisions shall be 
4    developed with stakeholder input, including from equity 
5    eligible persons, equity eligible contractors, and 
6    community-based organizations that work with such persons 
7    and contractors.
8    (c-15) Racial discrimination elimination powers and 
9process.
10        (1) Purpose. It is the purpose of this subsection to 
11    empower the Agency and other State actors to remedy racial 
12    discrimination in Illinois' clean energy economy as 
13    effectively and expediently as possible, including through 
14    the use of race-conscious remedies, such as race-conscious 
15    contracting and hiring goals, as consistent with State and 
16    federal law.
17        (2) Racial disparity and discrimination review 
18    process.
19            (A) Within one year after awarding contracts using 
20        the equity actions processes established in this 
21        Section, the Agency shall publish a report evaluating 
22        the effectiveness of the equity actions point criteria 
23        of this Section in increasing participation of equity 
24        eligible persons and equity eligible contractors. The 
25        report shall disaggregate participating workers and 
26        contractors by race and ethnicity. The report shall be 
 
 
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1        forwarded to the Governor, the General Assembly, and 
2        the Illinois Commerce Commission and be made available 
3        to the public.
4            (B) As soon as is practicable thereafter, the 
5        Agency, in consultation with the Department of 
6        Commerce and Economic Opportunity, Department of 
7        Labor, and other agencies that may be relevant, shall 
8        commission and publish a disparity and availability 
9        study that measures the presence and impact of 
10        discrimination on minority businesses and workers in 
11        Illinois' clean energy economy. The Agency may hire 
12        consultants and experts to conduct the disparity and 
13        availability study, with the retention of those 
14        consultants and experts exempt from the requirements 
15        of Section 20-10 of the Illinois Procurement Code. The 
16        Illinois Power Agency shall forward a copy of its 
17        findings and recommendations to the Governor, the 
18        General Assembly, and the Illinois Commerce 
19        Commission. If the disparity and availability study 
20        establishes a strong basis in evidence that there is 
21        discrimination in Illinois' clean energy economy, the 
22        Agency, Department of Commerce and Economic 
23        Opportunity, Department of Labor, Department of 
24        Corrections, and other appropriate agencies shall take 
25        appropriate remedial actions, including race-conscious 
26        remedial actions as consistent with State and federal 
 
 
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1        law, to effectively remedy this discrimination. Such 
2        remedies may include modification of the equity 
3        accountability system as described in subsection 
4        (c-10).
5    (c-20) Program data collection.
6        (1) Purpose. Data collection, data analysis, and 
7    reporting are critical to ensure that the benefits of the 
8    clean energy economy provided to Illinois residents and 
9    businesses are equitably distributed across the State. The 
10    Agency shall collect data from program applicants in order 
11    to track and improve equitable distribution of benefits 
12    across Illinois communities for all procurements the 
13    Agency conducts. The Agency shall use this data to, among 
14    other things, measure any potential impact of racial 
15    discrimination on the distribution of benefits and provide 
16    information necessary to correct any discrimination 
17    through methods consistent with State and federal law.
18        (2) Agency collection of program data. The Agency 
19    shall collect demographic and geographic data for each 
20    entity awarded contracts under any Agency-administered 
21    program.
22        (3) Required information to be collected. The Agency 
23    shall collect the following information from applicants 
24    and program participants where applicable:
25            (A) demographic information, including racial or 
26        ethnic identity for real persons employed, contracted, 
 
 
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1        or subcontracted through the program and owners of 
2        businesses or entities that apply to receive renewable 
3        energy credits from the Agency;
4            (B) geographic location of the residency of real 
5        persons employed, contracted, or subcontracted through 
6        the program and geographic location of the 
7        headquarters of the business or entity that applies to 
8        receive renewable energy credits from the Agency; and
9            (C) any other information the Agency determines is 
10        necessary for the purpose of achieving the purpose of 
11        this subsection.
12        (4) Publication of collected information. The Agency 
13    shall publish, at least annually, information on the 
14    demographics of program participants on an aggregate 
15    basis.
16        (5) Nothing in this subsection shall be interpreted to 
17    limit the authority of the Agency, or other agency or 
18    department of the State, to require or collect demographic 
19    information from applicants of other State programs.
20    (c-25) Energy Workforce Equity Database.
21        (1) The Agency, in consultation with the Department of 
22    Commerce and Economic Opportunity, shall create an Energy 
23    Workforce Equity Database, and may contract with a third 
24    party to do so ("database program administrator"). If the 
25    Department decides to contract with a third party, that 
26    third party shall be exempt from the requirements of 
 
 
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1    Section 20-10 of the Illinois Procurement Code. The Energy 
2    Workforce Equity Database shall be a searchable database 
3    of suppliers, vendors, and subcontractors for clean energy 
4    industries that is:
5            (A) publicly accessible;
6            (B) easy for people to find and use;
7            (C) organized by company specialty or field;
8            (D) region-specific; and
9            (E) populated with information including, but not 
10        limited to, contacts for suppliers, vendors, or 
11        subcontractors who are minority and women-owned 
12        business enterprise certified or who participate or 
13        have participated in any of the programs described in 
14        this Act.
15        (2) The Agency shall create an easily accessible, 
16    public facing online tool using the database information 
17    that includes, at a minimum, the following:
18            (A) a map of environmental justice and equity 
19        investment eligible communities;
20            (B) job postings and recruiting opportunities;
21            (C) a means by which recruiting clean energy 
22        companies can find and interact with current or former 
23        participants of clean energy workforce training 
24        programs;
25            (D) information on workforce training service 
26        providers and training opportunities available to 
 
 
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1        prospective workers;
2            (E) renewable energy company diversity reporting;
3            (F) a list of equity eligible contractors with 
4        their contact information, types of work performed, 
5        and locations worked in;
6            (G) reporting on outcomes of the programs 
7        described in the workforce programs of the Energy 
8        Transition Act, including information such as, but not 
9        limited to, retention rate, graduation rate, and 
10        placement rates of trainees; and
11            (H) information about the Jobs and Environmental 
12        Justice Grant Program, the Clean Energy Jobs and 
13        Justice Fund, and other sources of capital.
14        (3) The Agency shall ensure the database is regularly 
15    updated to ensure information is current and shall 
16    coordinate with the Department of Commerce and Economic 
17    Opportunity to ensure that it includes information on 
18    individuals and entities that are or have participated in 
19    the Clean Jobs Workforce Network Program, Clean Energy 
20    Contractor Incubator Program, Returning Residents Clean 
21    Jobs Training Program, or Clean Energy Primes Contractor 
22    Accelerator Program.
23    (c-30) Enforcement of minimum equity standards. All 
24entities seeking renewable energy credits must submit an 
25annual report to demonstrate compliance with each of the 
26equity commitments required under subsection (c-10). If the 
 
 
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1Agency concludes the entity has not met or maintained its 
2minimum equity standards required under the applicable 
3subparagraphs under subsection (c-10), the Agency shall deny 
4the entity's ability to participate in procurement programs in 
5subsection (c), including by withholding approved vendor or 
6designee status. The Agency may require the entity to enter 
7into a corrective action plan. An entity that is not 
8recertified for failing to meet required equity actions in 
9subparagraph (c-10) may reapply once they have a corrective 
10action plan and achieve compliance with the minimum equity 
11standards.
12    (d) Clean coal portfolio standard.
13        (1) The procurement plans shall include electricity 
14    generated using clean coal. Each utility shall enter into 
15    one or more sourcing agreements with the initial clean 
16    coal facility, as provided in paragraph (3) of this 
17    subsection (d), covering electricity generated by the 
18    initial clean coal facility representing at least 5% of 
19    each utility's total supply to serve the load of eligible 
20    retail customers in 2015 and each year thereafter, as 
21    described in paragraph (3) of this subsection (d), subject 
22    to the limits specified in paragraph (2) of this 
23    subsection (d). It is the goal of the State that by January 
24    1, 2025, 25% of the electricity used in the State shall be 
25    generated by cost-effective clean coal facilities. For 
26    purposes of this subsection (d), "cost-effective" means 
 
 
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1    that the expenditures pursuant to such sourcing agreements 
2    do not cause the limit stated in paragraph (2) of this 
3    subsection (d) to be exceeded and do not exceed cost-based 
4    benchmarks, which shall be developed to assess all 
5    expenditures pursuant to such sourcing agreements covering 
6    electricity generated by clean coal facilities, other than 
7    the initial clean coal facility, by the procurement 
8    administrator, in consultation with the Commission staff, 
9    Agency staff, and the procurement monitor and shall be 
10    subject to Commission review and approval.
11        A utility party to a sourcing agreement shall 
12    immediately retire any emission credits that it receives 
13    in connection with the electricity covered by such 
14    agreement.
15        Utilities shall maintain adequate records documenting 
16    the purchases under the sourcing agreement to comply with 
17    this subsection (d) and shall file an accounting with the 
18    load forecast that must be filed with the Agency by July 15 
19    of each year, in accordance with subsection (d) of Section 
20    16-111.5 of the Public Utilities Act.
21        A utility shall be deemed to have complied with the 
22    clean coal portfolio standard specified in this subsection 
23    (d) if the utility enters into a sourcing agreement as 
24    required by this subsection (d). 
25        (2) For purposes of this subsection (d), the required 
26    execution of sourcing agreements with the initial clean 
 
 
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1    coal facility for a particular year shall be measured as a 
2    percentage of the actual amount of electricity 
3    (megawatt-hours) supplied by the electric utility to 
4    eligible retail customers in the planning year ending 
5    immediately prior to the agreement's execution. For 
6    purposes of this subsection (d), the amount paid per 
7    kilowatthour means the total amount paid for electric 
8    service expressed on a per kilowatthour basis. For 
9    purposes of this subsection (d), the total amount paid for 
10    electric service includes without limitation amounts paid 
11    for supply, transmission, distribution, surcharges and 
12    add-on taxes.
13        Notwithstanding the requirements of this subsection 
14    (d), the total amount paid under sourcing agreements with 
15    clean coal facilities pursuant to the procurement plan for 
16    any given year shall be reduced by an amount necessary to 
17    limit the annual estimated average net increase due to the 
18    costs of these resources included in the amounts paid by 
19    eligible retail customers in connection with electric 
20    service to:
21            (A) in 2010, no more than 0.5% of the amount paid 
22        per kilowatthour by those customers during the year 
23        ending May 31, 2009;
24            (B) in 2011, the greater of an additional 0.5% of 
25        the amount paid per kilowatthour by those customers 
26        during the year ending May 31, 2010 or 1% of the amount 
 
 
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1        paid per kilowatthour by those customers during the 
2        year ending May 31, 2009;
3            (C) in 2012, the greater of an additional 0.5% of 
4        the amount paid per kilowatthour by those customers 
5        during the year ending May 31, 2011 or 1.5% of the 
6        amount paid per kilowatthour by those customers during 
7        the year ending May 31, 2009;
8            (D) in 2013, the greater of an additional 0.5% of 
9        the amount paid per kilowatthour by those customers 
10        during the year ending May 31, 2012 or 2% of the amount 
11        paid per kilowatthour by those customers during the 
12        year ending May 31, 2009; and
13            (E) thereafter, the total amount paid under 
14        sourcing agreements with clean coal facilities 
15        pursuant to the procurement plan for any single year 
16        shall be reduced by an amount necessary to limit the 
17        estimated average net increase due to the cost of 
18        these resources included in the amounts paid by 
19        eligible retail customers in connection with electric 
20        service to no more than the greater of (i) 2.015% of 
21        the amount paid per kilowatthour by those customers 
22        during the year ending May 31, 2009 or (ii) the 
23        incremental amount per kilowatthour paid for these 
24        resources in 2013. These requirements may be altered 
25        only as provided by statute.
26        No later than June 30, 2015, the Commission shall 
 
 
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1    review the limitation on the total amount paid under 
2    sourcing agreements, if any, with clean coal facilities 
3    pursuant to this subsection (d) and report to the General 
4    Assembly its findings as to whether that limitation unduly 
5    constrains the amount of electricity generated by 
6    cost-effective clean coal facilities that is covered by 
7    sourcing agreements.
8        (3) Initial clean coal facility. In order to promote 
9    development of clean coal facilities in Illinois, each 
10    electric utility subject to this Section shall execute a 
11    sourcing agreement to source electricity from a proposed 
12    clean coal facility in Illinois (the "initial clean coal 
13    facility") that will have a nameplate capacity of at least 
14    500 MW when commercial operation commences, that has a 
15    final Clean Air Act permit on June 1, 2009 (the effective 
16    date of Public Act 95-1027), and that will meet the 
17    definition of clean coal facility in Section 1-10 of this 
18    Act when commercial operation commences. The sourcing 
19    agreements with this initial clean coal facility shall be 
20    subject to both approval of the initial clean coal 
21    facility by the General Assembly and satisfaction of the 
22    requirements of paragraph (4) of this subsection (d) and 
23    shall be executed within 90 days after any such approval 
24    by the General Assembly. The Agency and the Commission 
25    shall have authority to inspect all books and records 
26    associated with the initial clean coal facility during the 
 
 
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1    term of such a sourcing agreement. A utility's sourcing 
2    agreement for electricity produced by the initial clean 
3    coal facility shall include:
4            (A) a formula contractual price (the "contract 
5        price") approved pursuant to paragraph (4) of this 
6        subsection (d), which shall:
7                (i) be determined using a cost of service 
8            methodology employing either a level or deferred 
9            capital recovery component, based on a capital 
10            structure consisting of 45% equity and 55% debt, 
11            and a return on equity as may be approved by the 
12            Federal Energy Regulatory Commission, which in any 
13            case may not exceed the lower of 11.5% or the rate 
14            of return approved by the General Assembly 
15            pursuant to paragraph (4) of this subsection (d); 
16            and
17                (ii) provide that all miscellaneous net 
18            revenue, including but not limited to net revenue 
19            from the sale of emission allowances, if any, 
20            substitute natural gas, if any, grants or other 
21            support provided by the State of Illinois or the 
22            United States Government, firm transmission 
23            rights, if any, by-products produced by the 
24            facility, energy or capacity derived from the 
25            facility and not covered by a sourcing agreement 
26            pursuant to paragraph (3) of this subsection (d) 
 
 
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1            or item (5) of subsection (d) of Section 16-115 of 
2            the Public Utilities Act, whether generated from 
3            the synthesis gas derived from coal, from SNG, or 
4            from natural gas, shall be credited against the 
5            revenue requirement for this initial clean coal 
6            facility;
7            (B) power purchase provisions, which shall: 
8                (i) provide that the utility party to such 
9            sourcing agreement shall pay the contract price 
10            for electricity delivered under such sourcing 
11            agreement; 
12                (ii) require delivery of electricity to the 
13            regional transmission organization market of the 
14            utility that is party to such sourcing agreement;
15                (iii) require the utility party to such 
16            sourcing agreement to buy from the initial clean 
17            coal facility in each hour an amount of energy 
18            equal to all clean coal energy made available from 
19            the initial clean coal facility during such hour 
20            times a fraction, the numerator of which is such 
21            utility's retail market sales of electricity 
22            (expressed in kilowatthours sold) in the State 
23            during the prior calendar month and the 
24            denominator of which is the total retail market 
25            sales of electricity (expressed in kilowatthours 
26            sold) in the State by utilities during such prior 
 
 
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1            month and the sales of electricity (expressed in 
2            kilowatthours sold) in the State by alternative 
3            retail electric suppliers during such prior month 
4            that are subject to the requirements of this 
5            subsection (d) and paragraph (5) of subsection (d) 
6            of Section 16-115 of the Public Utilities Act, 
7            provided that the amount purchased by the utility 
8            in any year will be limited by paragraph (2) of 
9            this subsection (d); and
10                (iv) be considered pre-existing contracts in 
11            such utility's procurement plans for eligible 
12            retail customers;
13            (C) contract for differences provisions, which 
14        shall:
15                (i) require the utility party to such sourcing 
16            agreement to contract with the initial clean coal 
17            facility in each hour with respect to an amount of 
18            energy equal to all clean coal energy made 
19            available from the initial clean coal facility 
20            during such hour times a fraction, the numerator 
21            of which is such utility's retail market sales of 
22            electricity (expressed in kilowatthours sold) in 
23            the utility's service territory in the State 
24            during the prior calendar month and the 
25            denominator of which is the total retail market 
26            sales of electricity (expressed in kilowatthours 
 
 
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1            sold) in the State by utilities during such prior 
2            month and the sales of electricity (expressed in 
3            kilowatthours sold) in the State by alternative 
4            retail electric suppliers during such prior month 
5            that are subject to the requirements of this 
6            subsection (d) and paragraph (5) of subsection (d) 
7            of Section 16-115 of the Public Utilities Act, 
8            provided that the amount paid by the utility in 
9            any year will be limited by paragraph (2) of this 
10            subsection (d);
11                (ii) provide that the utility's payment 
12            obligation in respect of the quantity of 
13            electricity determined pursuant to the preceding 
14            clause (i) shall be limited to an amount equal to 
15            (1) the difference between the contract price 
16            determined pursuant to subparagraph (A) of 
17            paragraph (3) of this subsection (d) and the 
18            day-ahead price for electricity delivered to the 
19            regional transmission organization market of the 
20            utility that is party to such sourcing agreement 
21            (or any successor delivery point at which such 
22            utility's supply obligations are financially 
23            settled on an hourly basis) (the "reference 
24            price") on the day preceding the day on which the 
25            electricity is delivered to the initial clean coal 
26            facility busbar, multiplied by (2) the quantity of 
 
 
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1            electricity determined pursuant to the preceding 
2            clause (i); and
3                (iii) not require the utility to take physical 
4            delivery of the electricity produced by the 
5            facility;
6            (D) general provisions, which shall:
7                (i) specify a term of no more than 30 years, 
8            commencing on the commercial operation date of the 
9            facility;
10                (ii) provide that utilities shall maintain 
11            adequate records documenting purchases under the 
12            sourcing agreements entered into to comply with 
13            this subsection (d) and shall file an accounting 
14            with the load forecast that must be filed with the 
15            Agency by July 15 of each year, in accordance with 
16            subsection (d) of Section 16-111.5 of the Public 
17            Utilities Act; 
18                (iii) provide that all costs associated with 
19            the initial clean coal facility will be 
20            periodically reported to the Federal Energy 
21            Regulatory Commission and to purchasers in 
22            accordance with applicable laws governing 
23            cost-based wholesale power contracts;
24                (iv) permit the Illinois Power Agency to 
25            assume ownership of the initial clean coal 
26            facility, without monetary consideration and 
 
 
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1            otherwise on reasonable terms acceptable to the 
2            Agency, if the Agency so requests no less than 3 
3            years prior to the end of the stated contract 
4            term;
5                (v) require the owner of the initial clean 
6            coal facility to provide documentation to the 
7            Commission each year, starting in the facility's 
8            first year of commercial operation, accurately 
9            reporting the quantity of carbon emissions from 
10            the facility that have been captured and 
11            sequestered and report any quantities of carbon 
12            released from the site or sites at which carbon 
13            emissions were sequestered in prior years, based 
14            on continuous monitoring of such sites. If, in any 
15            year after the first year of commercial operation, 
16            the owner of the facility fails to demonstrate 
17            that the initial clean coal facility captured and 
18            sequestered at least 50% of the total carbon 
19            emissions that the facility would otherwise emit 
20            or that sequestration of emissions from prior 
21            years has failed, resulting in the release of 
22            carbon dioxide into the atmosphere, the owner of 
23            the facility must offset excess emissions. Any 
24            such carbon offsets must be permanent, additional, 
25            verifiable, real, located within the State of 
26            Illinois, and legally and practicably enforceable. 
 
 
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1            The cost of such offsets for the facility that are 
2            not recoverable shall not exceed $15 million in 
3            any given year. No costs of any such purchases of 
4            carbon offsets may be recovered from a utility or 
5            its customers. All carbon offsets purchased for 
6            this purpose and any carbon emission credits 
7            associated with sequestration of carbon from the 
8            facility must be permanently retired. The initial 
9            clean coal facility shall not forfeit its 
10            designation as a clean coal facility if the 
11            facility fails to fully comply with the applicable 
12            carbon sequestration requirements in any given 
13            year, provided the requisite offsets are 
14            purchased. However, the Attorney General, on 
15            behalf of the People of the State of Illinois, may 
16            specifically enforce the facility's sequestration 
17            requirement and the other terms of this contract 
18            provision. Compliance with the sequestration 
19            requirements and offset purchase requirements 
20            specified in paragraph (3) of this subsection (d) 
21            shall be reviewed annually by an independent 
22            expert retained by the owner of the initial clean 
23            coal facility, with the advance written approval 
24            of the Attorney General. The Commission may, in 
25            the course of the review specified in item (vii), 
26            reduce the allowable return on equity for the 
 
 
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1            facility if the facility willfully fails to comply 
2            with the carbon capture and sequestration 
3            requirements set forth in this item (v);
4                (vi) include limits on, and accordingly 
5            provide for modification of, the amount the 
6            utility is required to source under the sourcing 
7            agreement consistent with paragraph (2) of this 
8            subsection (d);
9                (vii) require Commission review: (1) to 
10            determine the justness, reasonableness, and 
11            prudence of the inputs to the formula referenced 
12            in subparagraphs (A)(i) through (A)(iii) of 
13            paragraph (3) of this subsection (d), prior to an 
14            adjustment in those inputs including, without 
15            limitation, the capital structure and return on 
16            equity, fuel costs, and other operations and 
17            maintenance costs and (2) to approve the costs to 
18            be passed through to customers under the sourcing 
19            agreement by which the utility satisfies its 
20            statutory obligations. Commission review shall 
21            occur no less than every 3 years, regardless of 
22            whether any adjustments have been proposed, and 
23            shall be completed within 9 months; 
24                (viii) limit the utility's obligation to such 
25            amount as the utility is allowed to recover 
26            through tariffs filed with the Commission, 
 
 
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1            provided that neither the clean coal facility nor 
2            the utility waives any right to assert federal 
3            pre-emption or any other argument in response to a 
4            purported disallowance of recovery costs;
5                (ix) limit the utility's or alternative retail 
6            electric supplier's obligation to incur any 
7            liability until such time as the facility is in 
8            commercial operation and generating power and 
9            energy and such power and energy is being 
10            delivered to the facility busbar;
11                (x) provide that the owner or owners of the 
12            initial clean coal facility, which is the 
13            counterparty to such sourcing agreement, shall 
14            have the right from time to time to elect whether 
15            the obligations of the utility party thereto shall 
16            be governed by the power purchase provisions or 
17            the contract for differences provisions;
18                (xi) append documentation showing that the 
19            formula rate and contract, insofar as they relate 
20            to the power purchase provisions, have been 
21            approved by the Federal Energy Regulatory 
22            Commission pursuant to Section 205 of the Federal 
23            Power Act;
24                (xii) provide that any changes to the terms of 
25            the contract, insofar as such changes relate to 
26            the power purchase provisions, are subject to 
 
 
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1            review under the public interest standard applied 
2            by the Federal Energy Regulatory Commission 
3            pursuant to Sections 205 and 206 of the Federal 
4            Power Act; and
5                (xiii) conform with customary lender 
6            requirements in power purchase agreements used as 
7            the basis for financing non-utility generators. 
8        (4) Effective date of sourcing agreements with the 
9    initial clean coal facility. Any proposed sourcing 
10    agreement with the initial clean coal facility shall not 
11    become effective unless the following reports are prepared 
12    and submitted and authorizations and approvals obtained:
13            (i) Facility cost report. The owner of the initial 
14        clean coal facility shall submit to the Commission, 
15        the Agency, and the General Assembly a front-end 
16        engineering and design study, a facility cost report, 
17        method of financing (including but not limited to 
18        structure and associated costs), and an operating and 
19        maintenance cost quote for the facility (collectively 
20        "facility cost report"), which shall be prepared in 
21        accordance with the requirements of this paragraph (4) 
22        of subsection (d) of this Section, and shall provide 
23        the Commission and the Agency access to the work 
24        papers, relied upon documents, and any other backup 
25        documentation related to the facility cost report.
26            (ii) Commission report. Within 6 months following 
 
 
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1        receipt of the facility cost report, the Commission, 
2        in consultation with the Agency, shall submit a report 
3        to the General Assembly setting forth its analysis of 
4        the facility cost report. Such report shall include, 
5        but not be limited to, a comparison of the costs 
6        associated with electricity generated by the initial 
7        clean coal facility to the costs associated with 
8        electricity generated by other types of generation 
9        facilities, an analysis of the rate impacts on 
10        residential and small business customers over the life 
11        of the sourcing agreements, and an analysis of the 
12        likelihood that the initial clean coal facility will 
13        commence commercial operation by and be delivering 
14        power to the facility's busbar by 2016. To assist in 
15        the preparation of its report, the Commission, in 
16        consultation with the Agency, may hire one or more 
17        experts or consultants, the costs of which shall be 
18        paid for by the owner of the initial clean coal 
19        facility. The Commission and Agency may begin the 
20        process of selecting such experts or consultants prior 
21        to receipt of the facility cost report.
22            (iii) General Assembly approval. The proposed 
23        sourcing agreements shall not take effect unless, 
24        based on the facility cost report and the Commission's 
25        report, the General Assembly enacts authorizing 
26        legislation approving (A) the projected price, stated 
 
 
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1        in cents per kilowatthour, to be charged for 
2        electricity generated by the initial clean coal 
3        facility, (B) the projected impact on residential and 
4        small business customers' bills over the life of the 
5        sourcing agreements, and (C) the maximum allowable 
6        return on equity for the project; and
7            (iv) Commission review. If the General Assembly 
8        enacts authorizing legislation pursuant to 
9        subparagraph (iii) approving a sourcing agreement, the 
10        Commission shall, within 90 days of such enactment, 
11        complete a review of such sourcing agreement. During 
12        such time period, the Commission shall implement any 
13        directive of the General Assembly, resolve any 
14        disputes between the parties to the sourcing agreement 
15        concerning the terms of such agreement, approve the 
16        form of such agreement, and issue an order finding 
17        that the sourcing agreement is prudent and reasonable.
18        The facility cost report shall be prepared as follows: 
19            (A) The facility cost report shall be prepared by 
20        duly licensed engineering and construction firms 
21        detailing the estimated capital costs payable to one 
22        or more contractors or suppliers for the engineering, 
23        procurement and construction of the components 
24        comprising the initial clean coal facility and the 
25        estimated costs of operation and maintenance of the 
26        facility. The facility cost report shall include:
 
 
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1                (i) an estimate of the capital cost of the 
2            core plant based on one or more front end 
3            engineering and design studies for the 
4            gasification island and related facilities. The 
5            core plant shall include all civil, structural, 
6            mechanical, electrical, control, and safety 
7            systems.
8                (ii) an estimate of the capital cost of the 
9            balance of the plant, including any capital costs 
10            associated with sequestration of carbon dioxide 
11            emissions and all interconnects and interfaces 
12            required to operate the facility, such as 
13            transmission of electricity, construction or 
14            backfeed power supply, pipelines to transport 
15            substitute natural gas or carbon dioxide, potable 
16            water supply, natural gas supply, water supply, 
17            water discharge, landfill, access roads, and coal 
18            delivery.
19            The quoted construction costs shall be expressed 
20        in nominal dollars as of the date that the quote is 
21        prepared and shall include capitalized financing costs 
22        during construction, taxes, insurance, and other 
23        owner's costs, and an assumed escalation in materials 
24        and labor beyond the date as of which the construction 
25        cost quote is expressed.
26            (B) The front end engineering and design study for 
 
 
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1        the gasification island and the cost study for the 
2        balance of plant shall include sufficient design work 
3        to permit quantification of major categories of 
4        materials, commodities and labor hours, and receipt of 
5        quotes from vendors of major equipment required to 
6        construct and operate the clean coal facility.
7            (C) The facility cost report shall also include an 
8        operating and maintenance cost quote that will provide 
9        the estimated cost of delivered fuel, personnel, 
10        maintenance contracts, chemicals, catalysts, 
11        consumables, spares, and other fixed and variable 
12        operations and maintenance costs. The delivered fuel 
13        cost estimate will be provided by a recognized third 
14        party expert or experts in the fuel and transportation 
15        industries. The balance of the operating and 
16        maintenance cost quote, excluding delivered fuel 
17        costs, will be developed based on the inputs provided 
18        by duly licensed engineering and construction firms 
19        performing the construction cost quote, potential 
20        vendors under long-term service agreements and plant 
21        operating agreements, or recognized third party plant 
22        operator or operators.
23            The operating and maintenance cost quote 
24        (including the cost of the front end engineering and 
25        design study) shall be expressed in nominal dollars as 
26        of the date that the quote is prepared and shall 
 
 
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1        include taxes, insurance, and other owner's costs, and 
2        an assumed escalation in materials and labor beyond 
3        the date as of which the operating and maintenance 
4        cost quote is expressed.
5            (D) The facility cost report shall also include an 
6        analysis of the initial clean coal facility's ability 
7        to deliver power and energy into the applicable 
8        regional transmission organization markets and an 
9        analysis of the expected capacity factor for the 
10        initial clean coal facility. 
11            (E) Amounts paid to third parties unrelated to the 
12        owner or owners of the initial clean coal facility to 
13        prepare the core plant construction cost quote, 
14        including the front end engineering and design study, 
15        and the operating and maintenance cost quote will be 
16        reimbursed through Coal Development Bonds.
17        (5) Re-powering and retrofitting coal-fired power 
18    plants previously owned by Illinois utilities to qualify 
19    as clean coal facilities. During the 2009 procurement 
20    planning process and thereafter, the Agency and the 
21    Commission shall consider sourcing agreements covering 
22    electricity generated by power plants that were previously 
23    owned by Illinois utilities and that have been or will be 
24    converted into clean coal facilities, as defined by 
25    Section 1-10 of this Act. Pursuant to such procurement 
26    planning process, the owners of such facilities may 
 
 
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1    propose to the Agency sourcing agreements with utilities 
2    and alternative retail electric suppliers required to 
3    comply with subsection (d) of this Section and item (5) of 
4    subsection (d) of Section 16-115 of the Public Utilities 
5    Act, covering electricity generated by such facilities. In 
6    the case of sourcing agreements that are power purchase 
7    agreements, the contract price for electricity sales shall 
8    be established on a cost of service basis. In the case of 
9    sourcing agreements that are contracts for differences, 
10    the contract price from which the reference price is 
11    subtracted shall be established on a cost of service 
12    basis. The Agency and the Commission may approve any such 
13    utility sourcing agreements that do not exceed cost-based 
14    benchmarks developed by the procurement administrator, in 
15    consultation with the Commission staff, Agency staff and 
16    the procurement monitor, subject to Commission review and 
17    approval. The Commission shall have authority to inspect 
18    all books and records associated with these clean coal 
19    facilities during the term of any such contract.
20        (6) Costs incurred under this subsection (d) or 
21    pursuant to a contract entered into under this subsection 
22    (d) shall be deemed prudently incurred and reasonable in 
23    amount and the electric utility shall be entitled to full 
24    cost recovery pursuant to the tariffs filed with the 
25    Commission. 
26    (d-5) Zero emission standard.
 
 
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1        (1) Beginning with the delivery year commencing on 
2    June 1, 2017, the Agency shall, for electric utilities 
3    that serve at least 100,000 retail customers in this 
4    State, procure contracts with zero emission facilities 
5    that are reasonably capable of generating cost-effective 
6    zero emission credits in an amount approximately equal to 
7    16% of the actual amount of electricity delivered by each 
8    electric utility to retail customers in the State during 
9    calendar year 2014. For an electric utility serving fewer 
10    than 100,000 retail customers in this State that 
11    requested, under Section 16-111.5 of the Public Utilities 
12    Act, that the Agency procure power and energy for all or a 
13    portion of the utility's Illinois load for the delivery 
14    year commencing June 1, 2016, the Agency shall procure 
15    contracts with zero emission facilities that are 
16    reasonably capable of generating cost-effective zero 
17    emission credits in an amount approximately equal to 16% 
18    of the portion of power and energy to be procured by the 
19    Agency for the utility. The duration of the contracts 
20    procured under this subsection (d-5) shall be for a term 
21    of 10 years ending May 31, 2027. The quantity of zero 
22    emission credits to be procured under the contracts shall 
23    be all of the zero emission credits generated by the zero 
24    emission facility in each delivery year; however, if the 
25    zero emission facility is owned by more than one entity, 
26    then the quantity of zero emission credits to be procured 
 
 
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1    under the contracts shall be the amount of zero emission 
2    credits that are generated from the portion of the zero 
3    emission facility that is owned by the winning supplier.
4        The 16% value identified in this paragraph (1) is the 
5    average of the percentage targets in subparagraph (B) of 
6    paragraph (1) of subsection (c) of this Section for the 5 
7    delivery years beginning June 1, 2017.
8        The procurement process shall be subject to the 
9    following provisions:
10            (A) Those zero emission facilities that intend to 
11        participate in the procurement shall submit to the 
12        Agency the following eligibility information for each 
13        zero emission facility on or before the date 
14        established by the Agency:
15                (i) the in-service date and remaining useful 
16            life of the zero emission facility;
17                (ii) the amount of power generated annually 
18            for each of the years 2005 through 2015, and the 
19            projected zero emission credits to be generated 
20            over the remaining useful life of the zero 
21            emission facility, which shall be used to 
22            determine the capability of each facility;
23                (iii) the annual zero emission facility cost 
24            projections, expressed on a per megawatthour 
25            basis, over the next 6 delivery years, which shall 
26            include the following: operation and maintenance 
 
 
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1            expenses; fully allocated overhead costs, which 
2            shall be allocated using the methodology developed 
3            by the Institute for Nuclear Power Operations; 
4            fuel expenditures; non-fuel capital expenditures; 
5            spent fuel expenditures; a return on working 
6            capital; the cost of operational and market risks 
7            that could be avoided by ceasing operation; and 
8            any other costs necessary for continued 
9            operations, provided that "necessary" means, for 
10            purposes of this item (iii), that the costs could 
11            reasonably be avoided only by ceasing operations 
12            of the zero emission facility; and
13                (iv) a commitment to continue operating, for 
14            the duration of the contract or contracts executed 
15            under the procurement held under this subsection 
16            (d-5), the zero emission facility that produces 
17            the zero emission credits to be procured in the 
18            procurement.
19            The information described in item (iii) of this 
20        subparagraph (A) may be submitted on a confidential 
21        basis and shall be treated and maintained by the 
22        Agency, the procurement administrator, and the 
23        Commission as confidential and proprietary and exempt 
24        from disclosure under subparagraphs (a) and (g) of 
25        paragraph (1) of Section 7 of the Freedom of 
26        Information Act. The Office of Attorney General shall 
 
 
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1        have access to, and maintain the confidentiality of, 
2        such information pursuant to Section 6.5 of the 
3        Attorney General Act. 
4            (B) The price for each zero emission credit 
5        procured under this subsection (d-5) for each delivery 
6        year shall be in an amount that equals the Social Cost 
7        of Carbon, expressed on a price per megawatthour 
8        basis. However, to ensure that the procurement remains 
9        affordable to retail customers in this State if 
10        electricity prices increase, the price in an 
11        applicable delivery year shall be reduced below the 
12        Social Cost of Carbon by the amount ("Price 
13        Adjustment") by which the market price index for the 
14        applicable delivery year exceeds the baseline market 
15        price index for the consecutive 12-month period ending 
16        May 31, 2016. If the Price Adjustment is greater than 
17        or equal to the Social Cost of Carbon in an applicable 
18        delivery year, then no payments shall be due in that 
19        delivery year. The components of this calculation are 
20        defined as follows:
21                (i) Social Cost of Carbon: The Social Cost of 
22            Carbon is $16.50 per megawatthour, which is based 
23            on the U.S. Interagency Working Group on Social 
24            Cost of Carbon's price in the August 2016 
25            Technical Update using a 3% discount rate, 
26            adjusted for inflation for each year of the 
 
 
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1            program. Beginning with the delivery year 
2            commencing June 1, 2023, the price per 
3            megawatthour shall increase by $1 per 
4            megawatthour, and continue to increase by an 
5            additional $1 per megawatthour each delivery year 
6            thereafter.
7                (ii) Baseline market price index: The baseline 
8            market price index for the consecutive 12-month 
9            period ending May 31, 2016 is $31.40 per 
10            megawatthour, which is based on the sum of (aa) 
11            the average day-ahead energy price across all 
12            hours of such 12-month period at the PJM 
13            Interconnection LLC Northern Illinois Hub, (bb) 
14            50% multiplied by the Base Residual Auction, or 
15            its successor, capacity price for the rest of the 
16            RTO zone group determined by PJM Interconnection 
17            LLC, divided by 24 hours per day, and (cc) 50% 
18            multiplied by the Planning Resource Auction, or 
19            its successor, capacity price for Zone 4 
20            determined by the Midcontinent Independent System 
21            Operator, Inc., divided by 24 hours per day. 
22                (iii) Market price index: The market price 
23            index for a delivery year shall be the sum of 
24            projected energy prices and projected capacity 
25            prices determined as follows:
26                    (aa) Projected energy prices: the 
 
 
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1                projected energy prices for the applicable 
2                delivery year shall be calculated once for the 
3                year using the forward market price for the 
4                PJM Interconnection, LLC Northern Illinois 
5                Hub. The forward market price shall be 
6                calculated as follows: the energy forward 
7                prices for each month of the applicable 
8                delivery year averaged for each trade date 
9                during the calendar year immediately preceding 
10                that delivery year to produce a single energy 
11                forward price for the delivery year. The 
12                forward market price calculation shall use 
13                data published by the Intercontinental 
14                Exchange, or its successor.
15                    (bb) Projected capacity prices:
16                        (I) For the delivery years commencing 
17                    June 1, 2017, June 1, 2018, and June 1, 
18                    2019, the projected capacity price shall 
19                    be equal to the sum of (1) 50% multiplied 
20                    by the Base Residual Auction, or its 
21                    successor, price for the rest of the RTO 
22                    zone group as determined by PJM 
23                    Interconnection LLC, divided by 24 hours 
24                    per day and, (2) 50% multiplied by the 
25                    resource auction price determined in the 
26                    resource auction administered by the 
 
 
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1                    Midcontinent Independent System Operator, 
2                    Inc., in which the largest percentage of 
3                    load cleared for Local Resource Zone 4, 
4                    divided by 24 hours per day, and where 
5                    such price is determined by the 
6                    Midcontinent Independent System Operator, 
7                    Inc.
8                        (II) For the delivery year commencing 
9                    June 1, 2020, and each year thereafter, 
10                    the projected capacity price shall be 
11                    equal to the sum of (1) 50% multiplied by 
12                    the Base Residual Auction, or its 
13                    successor, price for the ComEd zone as 
14                    determined by PJM Interconnection LLC, 
15                    divided by 24 hours per day, and (2) 50% 
16                    multiplied by the resource auction price 
17                    determined in the resource auction 
18                    administered by the Midcontinent 
19                    Independent System Operator, Inc., in 
20                    which the largest percentage of load 
21                    cleared for Local Resource Zone 4, divided 
22                    by 24 hours per day, and where such price 
23                    is determined by the Midcontinent 
24                    Independent System Operator, Inc.
25            For purposes of this subsection (d-5):
26                "Rest of the RTO" and "ComEd Zone" shall have 
 
 
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1            the meaning ascribed to them by PJM 
2            Interconnection, LLC. 
3                "RTO" means regional transmission 
4            organization. 
5            (C) No later than 45 days after June 1, 2017 (the 
6        effective date of Public Act 99-906), the Agency shall 
7        publish its proposed zero emission standard 
8        procurement plan. The plan shall be consistent with 
9        the provisions of this paragraph (1) and shall provide 
10        that winning bids shall be selected based on public 
11        interest criteria that include, but are not limited 
12        to, minimizing carbon dioxide emissions that result 
13        from electricity consumed in Illinois and minimizing 
14        sulfur dioxide, nitrogen oxide, and particulate matter 
15        emissions that adversely affect the citizens of this 
16        State. In particular, the selection of winning bids 
17        shall take into account the incremental environmental 
18        benefits resulting from the procurement, such as any 
19        existing environmental benefits that are preserved by 
20        the procurements held under Public Act 99-906 and 
21        would cease to exist if the procurements were not 
22        held, including the preservation of zero emission 
23        facilities. The plan shall also describe in detail how 
24        each public interest factor shall be considered and 
25        weighted in the bid selection process to ensure that 
26        the public interest criteria are applied to the 
 
 
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1        procurement and given full effect.
2            For purposes of developing the plan, the Agency 
3        shall consider any reports issued by a State agency, 
4        board, or commission under House Resolution 1146 of 
5        the 98th General Assembly and paragraph (4) of 
6        subsection (d) of this Section, as well as publicly 
7        available analyses and studies performed by or for 
8        regional transmission organizations that serve the 
9        State and their independent market monitors.
10            Upon publishing of the zero emission standard 
11        procurement plan, copies of the plan shall be posted 
12        and made publicly available on the Agency's website. 
13        All interested parties shall have 10 days following 
14        the date of posting to provide comment to the Agency on 
15        the plan. All comments shall be posted to the Agency's 
16        website. Following the end of the comment period, but 
17        no more than 60 days later than June 1, 2017 (the 
18        effective date of Public Act 99-906), the Agency shall 
19        revise the plan as necessary based on the comments 
20        received and file its zero emission standard 
21        procurement plan with the Commission.
22            If the Commission determines that the plan will 
23        result in the procurement of cost-effective zero 
24        emission credits, then the Commission shall, after 
25        notice and hearing, but no later than 45 days after the 
26        Agency filed the plan, approve the plan or approve 
 
 
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1        with modification. For purposes of this subsection 
2        (d-5), "cost effective" means the projected costs of 
3        procuring zero emission credits from zero emission 
4        facilities do not cause the limit stated in paragraph 
5        (2) of this subsection to be exceeded.
6            (C-5) As part of the Commission's review and 
7        acceptance or rejection of the procurement results, 
8        the Commission shall, in its public notice of 
9        successful bidders:
10                (i) identify how the winning bids satisfy the 
11            public interest criteria described in subparagraph 
12            (C) of this paragraph (1) of minimizing carbon 
13            dioxide emissions that result from electricity 
14            consumed in Illinois and minimizing sulfur 
15            dioxide, nitrogen oxide, and particulate matter 
16            emissions that adversely affect the citizens of 
17            this State;
18                (ii) specifically address how the selection of 
19            winning bids takes into account the incremental 
20            environmental benefits resulting from the 
21            procurement, including any existing environmental 
22            benefits that are preserved by the procurements 
23            held under Public Act 99-906 and would have ceased 
24            to exist if the procurements had not been held, 
25            such as the preservation of zero emission 
26            facilities;
 
 
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1                (iii) quantify the environmental benefit of 
2            preserving the resources identified in item (ii) 
3            of this subparagraph (C-5), including the 
4            following:
5                    (aa) the value of avoided greenhouse gas 
6                emissions measured as the product of the zero 
7                emission facilities' output over the contract 
8                term multiplied by the U.S. Environmental 
9                Protection Agency eGrid subregion carbon 
10                dioxide emission rate and the U.S. Interagency 
11                Working Group on Social Cost of Carbon's price 
12                in the August 2016 Technical Update using a 3% 
13                discount rate, adjusted for inflation for each 
14                delivery year; and
15                    (bb) the costs of replacement with other 
16                zero carbon dioxide resources, including wind 
17                and photovoltaic, based upon the simple 
18                average of the following:
19                        (I) the price, or if there is more 
20                    than one price, the average of the prices, 
21                    paid for renewable energy credits from new 
22                    utility-scale wind projects in the 
23                    procurement events specified in item (i) 
24                    of subparagraph (G) of paragraph (1) of 
25                    subsection (c) of this Section; and
26                        (II) the price, or if there is more 
 
 
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1                    than one price, the average of the prices, 
2                    paid for renewable energy credits from new 
3                    utility-scale solar projects and 
4                    brownfield site photovoltaic projects in 
5                    the procurement events specified in item 
6                    (ii) of subparagraph (G) of paragraph (1) 
7                    of subsection (c) of this Section and, 
8                    after January 1, 2015, renewable energy 
9                    credits from photovoltaic distributed 
10                    generation projects in procurement events 
11                    held under subsection (c) of this Section. 
12            Each utility shall enter into binding contractual 
13        arrangements with the winning suppliers.
14            The procurement described in this subsection 
15        (d-5), including, but not limited to, the execution of 
16        all contracts procured, shall be completed no later 
17        than May 10, 2017. Based on the effective date of 
18        Public Act 99-906, the Agency and Commission may, as 
19        appropriate, modify the various dates and timelines 
20        under this subparagraph and subparagraphs (C) and (D) 
21        of this paragraph (1). The procurement and plan 
22        approval processes required by this subsection (d-5) 
23        shall be conducted in conjunction with the procurement 
24        and plan approval processes required by subsection (c) 
25        of this Section and Section 16-111.5 of the Public 
26        Utilities Act, to the extent practicable. 
 
 
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1        Notwithstanding whether a procurement event is 
2        conducted under Section 16-111.5 of the Public 
3        Utilities Act, the Agency shall immediately initiate a 
4        procurement process on June 1, 2017 (the effective 
5        date of Public Act 99-906).
6            (D) Following the procurement event described in 
7        this paragraph (1) and consistent with subparagraph 
8        (B) of this paragraph (1), the Agency shall calculate 
9        the payments to be made under each contract for the 
10        next delivery year based on the market price index for 
11        that delivery year. The Agency shall publish the 
12        payment calculations no later than May 25, 2017 and 
13        every May 25 thereafter.
14            (E) Notwithstanding the requirements of this 
15        subsection (d-5), the contracts executed under this 
16        subsection (d-5) shall provide that the zero emission 
17        facility may, as applicable, suspend or terminate 
18        performance under the contracts in the following 
19        instances:
20                (i) A zero emission facility shall be excused 
21            from its performance under the contract for any 
22            cause beyond the control of the resource, 
23            including, but not restricted to, acts of God, 
24            flood, drought, earthquake, storm, fire, 
25            lightning, epidemic, war, riot, civil disturbance 
26            or disobedience, labor dispute, labor or material 
 
 
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1            shortage, sabotage, acts of public enemy, 
2            explosions, orders, regulations or restrictions 
3            imposed by governmental, military, or lawfully 
4            established civilian authorities, which, in any of 
5            the foregoing cases, by exercise of commercially 
6            reasonable efforts the zero emission facility 
7            could not reasonably have been expected to avoid, 
8            and which, by the exercise of commercially 
9            reasonable efforts, it has been unable to 
10            overcome. In such event, the zero emission 
11            facility shall be excused from performance for the 
12            duration of the event, including, but not limited 
13            to, delivery of zero emission credits, and no 
14            payment shall be due to the zero emission facility 
15            during the duration of the event.
16                (ii) A zero emission facility shall be 
17            permitted to terminate the contract if legislation 
18            is enacted into law by the General Assembly that 
19            imposes or authorizes a new tax, special 
20            assessment, or fee on the generation of 
21            electricity, the ownership or leasehold of a 
22            generating unit, or the privilege or occupation of 
23            such generation, ownership, or leasehold of 
24            generation units by a zero emission facility. 
25            However, the provisions of this item (ii) do not 
26            apply to any generally applicable tax, special 
 
 
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1            assessment or fee, or requirements imposed by 
2            federal law.
3                (iii) A zero emission facility shall be 
4            permitted to terminate the contract in the event 
5            that the resource requires capital expenditures in 
6            excess of $40,000,000 that were neither known nor 
7            reasonably foreseeable at the time it executed the 
8            contract and that a prudent owner or operator of 
9            such resource would not undertake.
10                (iv) A zero emission facility shall be 
11            permitted to terminate the contract in the event 
12            the Nuclear Regulatory Commission terminates the 
13            resource's license.
14            (F) If the zero emission facility elects to 
15        terminate a contract under subparagraph (E) of this 
16        paragraph (1), then the Commission shall reopen the 
17        docket in which the Commission approved the zero 
18        emission standard procurement plan under subparagraph 
19        (C) of this paragraph (1) and, after notice and 
20        hearing, enter an order acknowledging the contract 
21        termination election if such termination is consistent 
22        with the provisions of this subsection (d-5).
23        (2) For purposes of this subsection (d-5), the amount 
24    paid per kilowatthour means the total amount paid for 
25    electric service expressed on a per kilowatthour basis. 
26    For purposes of this subsection (d-5), the total amount 
 
 
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1    paid for electric service includes, without limitation, 
2    amounts paid for supply, transmission, distribution, 
3    surcharges, and add-on taxes.
4        Notwithstanding the requirements of this subsection 
5    (d-5), the contracts executed under this subsection (d-5) 
6    shall provide that the total of zero emission credits 
7    procured under a procurement plan shall be subject to the 
8    limitations of this paragraph (2). For each delivery year, 
9    the contractual volume receiving payments in such year 
10    shall be reduced for all retail customers based on the 
11    amount necessary to limit the net increase that delivery 
12    year to the costs of those credits included in the amounts 
13    paid by eligible retail customers in connection with 
14    electric service to no more than 1.65% of the amount paid 
15    per kilowatthour by eligible retail customers during the 
16    year ending May 31, 2009. The result of this computation 
17    shall apply to and reduce the procurement for all retail 
18    customers, and all those customers shall pay the same 
19    single, uniform cents per kilowatthour charge under 
20    subsection (k) of Section 16-108 of the Public Utilities 
21    Act. To arrive at a maximum dollar amount of zero emission 
22    credits to be paid for the particular delivery year, the 
23    resulting per kilowatthour amount shall be applied to the 
24    actual amount of kilowatthours of electricity delivered by 
25    the electric utility in the delivery year immediately 
26    prior to the procurement, to all retail customers in its 
 
 
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1    service territory. Unpaid contractual volume for any 
2    delivery year shall be paid in any subsequent delivery 
3    year in which such payments can be made without exceeding 
4    the amount specified in this paragraph (2). The 
5    calculations required by this paragraph (2) shall be made 
6    only once for each procurement plan year. Once the 
7    determination as to the amount of zero emission credits to 
8    be paid is made based on the calculations set forth in this 
9    paragraph (2), no subsequent rate impact determinations 
10    shall be made and no adjustments to those contract amounts 
11    shall be allowed. All costs incurred under those contracts 
12    and in implementing this subsection (d-5) shall be 
13    recovered by the electric utility as provided in this 
14    Section.
15        No later than June 30, 2019, the Commission shall 
16    review the limitation on the amount of zero emission 
17    credits procured under this subsection (d-5) and report to 
18    the General Assembly its findings as to whether that 
19    limitation unduly constrains the procurement of 
20    cost-effective zero emission credits. 
21        (3) Six years after the execution of a contract under 
22    this subsection (d-5), the Agency shall determine whether 
23    the actual zero emission credit payments received by the 
24    supplier over the 6-year period exceed the Average ZEC 
25    Payment. In addition, at the end of the term of a contract 
26    executed under this subsection (d-5), or at the time, if 
 
 
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1    any, a zero emission facility's contract is terminated 
2    under subparagraph (E) of paragraph (1) of this subsection 
3    (d-5), then the Agency shall determine whether the actual 
4    zero emission credit payments received by the supplier 
5    over the term of the contract exceed the Average ZEC 
6    Payment, after taking into account any amounts previously 
7    credited back to the utility under this paragraph (3). If 
8    the Agency determines that the actual zero emission credit 
9    payments received by the supplier over the relevant period 
10    exceed the Average ZEC Payment, then the supplier shall 
11    credit the difference back to the utility. The amount of 
12    the credit shall be remitted to the applicable electric 
13    utility no later than 120 days after the Agency's 
14    determination, which the utility shall reflect as a credit 
15    on its retail customer bills as soon as practicable; 
16    however, the credit remitted to the utility shall not 
17    exceed the total amount of payments received by the 
18    facility under its contract.
19        For purposes of this Section, the Average ZEC Payment 
20    shall be calculated by multiplying the quantity of zero 
21    emission credits delivered under the contract times the 
22    average contract price. The average contract price shall 
23    be determined by subtracting the amount calculated under 
24    subparagraph (B) of this paragraph (3) from the amount 
25    calculated under subparagraph (A) of this paragraph (3), 
26    as follows:
 
 
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1            (A) The average of the Social Cost of Carbon, as 
2        defined in subparagraph (B) of paragraph (1) of this 
3        subsection (d-5), during the term of the contract.
4            (B) The average of the market price indices, as 
5        defined in subparagraph (B) of paragraph (1) of this 
6        subsection (d-5), during the term of the contract, 
7        minus the baseline market price index, as defined in 
8        subparagraph (B) of paragraph (1) of this subsection 
9        (d-5).
10        If the subtraction yields a negative number, then the 
11    Average ZEC Payment shall be zero. 
12        (4) Cost-effective zero emission credits procured from 
13    zero emission facilities shall satisfy the applicable 
14    definitions set forth in Section 1-10 of this Act.
15        (5) The electric utility shall retire all zero 
16    emission credits used to comply with the requirements of 
17    this subsection (d-5).
18        (6) Electric utilities shall be entitled to recover 
19    all of the costs associated with the procurement of zero 
20    emission credits through an automatic adjustment clause 
21    tariff in accordance with subsection (k) and (m) of 
22    Section 16-108 of the Public Utilities Act, and the 
23    contracts executed under this subsection (d-5) shall 
24    provide that the utilities' payment obligations under such 
25    contracts shall be reduced if an adjustment is required 
26    under subsection (m) of Section 16-108 of the Public 
 
 
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1    Utilities Act.
2        (7) This subsection (d-5) shall become inoperative on 
3    January 1, 2028. 
4    (d-10) Nuclear Plant Assistance; carbon mitigation 
5credits.
6    (1) The General Assembly finds:
7        (A) The health, welfare, and prosperity of all 
8    Illinois citizens require that the State of Illinois act 
9    to avoid and not increase carbon emissions from electric 
10    generation sources while continuing to ensure affordable, 
11    stable, and reliable electricity to all citizens.
12        (B) Absent immediate action by the State to preserve 
13    existing carbon-free energy resources, those resources may 
14    retire, and the electric generation needs of Illinois' 
15    retail customers may be met instead by facilities that 
16    emit significant amounts of carbon pollution and other 
17    harmful air pollutants at a high social and economic cost 
18    until Illinois is able to develop other forms of clean 
19    energy.
20        (C) The General Assembly finds that nuclear power 
21    generation is necessary for the State's transition to 100% 
22    clean energy, and ensuring continued operation of nuclear 
23    plants advances environmental and public health interests 
24    through providing carbon-free electricity while reducing 
25    the air pollution profile of the Illinois energy 
26    generation fleet.
 
 
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1        (D) The clean energy attributes of nuclear generation 
2    facilities support the State in its efforts to achieve 
3    100% clean energy.
4        (E) The State currently invests in various forms of 
5    clean energy, including, but not limited to, renewable 
6    energy, energy efficiency, and low-emission vehicles, 
7    among others.
8        (F) The Environmental Protection Agency commissioned 
9    an independent audit which provided a detailed assessment 
10    of the financial condition of the Illinois nuclear fleet 
11    to evaluate its financial viability and whether the 
12    environmental benefits of such resources were at risk. The 
13    report identified the risk of losing the environmental 
14    benefits of several specific nuclear units. The report 
15    also identified that the LaSalle County Generating Station 
16    will continue to operate through 2026 and therefore is not 
17    eligible to participate in the carbon mitigation credit 
18    program.
19        (G) Nuclear plants provide carbon-free energy, which 
20    helps to avoid many health-related negative impacts for 
21    Illinois residents.
22        (H) The procurement of carbon mitigation credits 
23    representing the environmental benefits of carbon-free 
24    generation will further the State's efforts at achieving 
25    100% clean energy and decarbonizing the electricity sector 
26    in a safe, reliable, and affordable manner. Further, the 
 
 
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1    procurement of carbon emission credits will enhance the 
2    health and welfare of Illinois residents through decreased 
3    reliance on more highly polluting generation.
4        (I) The General Assembly therefore finds it necessary 
5    to establish carbon mitigation credits to ensure decreased 
6    reliance on more carbon-intensive energy resources, for 
7    transitioning to a fully decarbonized electricity sector, 
8    and to help ensure health and welfare of the State's 
9    residents.
10    (2) As used in this subsection:
11    "Baseline costs" means costs used to establish a customer 
12protection cap that have been evaluated through an independent 
13audit of a carbon-free energy resource conducted by the 
14Environmental Protection Agency that evaluated projected 
15annual costs for operation and maintenance expenses; fully 
16allocated overhead costs, which shall be allocated using the 
17methodology developed by the Institute for Nuclear Power 
18Operations; fuel expenditures; nonfuel capital expenditures; 
19spent fuel expenditures; a return on working capital; the cost 
20of operational and market risks that could be avoided by 
21ceasing operation; and any other costs necessary for continued 
22operations, provided that "necessary" means, for purposes of 
23this definition, that the costs could reasonably be avoided 
24only by ceasing operations of the carbon-free energy resource.
25    "Carbon mitigation credit" means a tradable credit that 
26represents the carbon emission reduction attributes of one 
 
 
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1megawatt-hour of energy produced from a carbon-free energy 
2resource.
3    "Carbon-free energy resource" means a generation facility 
4that: (1) is fueled by nuclear power; and (2) is 
5interconnected to PJM Interconnection, LLC.
6    (3) Procurement.
7        (A) Beginning with the delivery year commencing on 
8    June 1, 2022, the Agency shall, for electric utilities 
9    serving at least 3,000,000 retail customers in the State, 
10    seek to procure contracts for no more than approximately 
11    54,500,000 cost-effective carbon mitigation credits from 
12    carbon-free energy resources because such credits are 
13    necessary to support current levels of carbon-free energy 
14    generation and ensure the State meets its carbon dioxide 
15    emissions reduction goals. The Agency shall not make a 
16    partial award of a contract for carbon mitigation credits 
17    covering a fractional amount of a carbon-free energy 
18    resource's projected output.
19        (B) Each carbon-free energy resource that intends to 
20    participate in a procurement shall be required to submit 
21    to the Agency the following information for the resource 
22    on or before the date established by the Agency:
23            (i) the in-service date and remaining useful life 
24        of the carbon-free energy resource;
25            (ii) the amount of power generated annually for 
26        each of the past 10 years, which shall be used to 
 
 
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1        determine the capability of each facility;
2            (iii) a commitment to be reflected in any contract 
3        entered into pursuant to this subsection (d-10) to 
4        continue operating the carbon-free energy resource at 
5        a capacity factor of at least 88% annually on average 
6        for the duration of the contract or contracts executed 
7        under the procurement held under this subsection 
8        (d-10), except in an instance described in 
9        subparagraph (E) of paragraph (1) of subsection (d-5) 
10        of this Section or made impracticable as a result of 
11        compliance with law or regulation;
12            (iv) financial need and the risk of loss of the 
13        environmental benefits of such resource, which shall 
14        include the following information:
15                (I) the carbon-free energy resource's cost 
16            projections, expressed on a per megawatt-hour 
17            basis, over the next 5 delivery years, which shall 
18            include the following: operation and maintenance 
19            expenses; fully allocated overhead costs, which 
20            shall be allocated using the methodology developed 
21            by the Institute for Nuclear Power Operations; 
22            fuel expenditures; nonfuel capital expenditures; 
23            spent fuel expenditures; a return on working 
24            capital; the cost of operational and market risks 
25            that could be avoided by ceasing operation; and 
26            any other costs necessary for continued 
 
 
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1            operations, provided that "necessary" means, for 
2            purposes of this subitem (I), that the costs could 
3            reasonably be avoided only by ceasing operations 
4            of the carbon-free energy resource; and
5                (II) the carbon-free energy resource's revenue 
6            projections, including energy, capacity, ancillary 
7            services, any other direct State support, known or 
8            anticipated federal attribute credits, known or 
9            anticipated tax credits, and any other direct 
10            federal support.
11        The information described in this subparagraph (B) may 
12    be submitted on a confidential basis and shall be treated 
13    and maintained by the Agency, the procurement 
14    administrator, and the Commission as confidential and 
15    proprietary and exempt from disclosure under subparagraphs 
16    (a) and (g) of paragraph (1) of Section 7 of the Freedom of 
17    Information Act. The Office of the Attorney General shall 
18    have access to, and maintain the confidentiality of, such 
19    information pursuant to Section 6.5 of the Attorney 
20    General Act. 
21        (C) The Agency shall solicit bids for the contracts 
22    described in this subsection (d-10) from carbon-free 
23    energy resources that have satisfied the requirements of 
24    subparagraph (B) of this paragraph (3). The contracts 
25    procured pursuant to a procurement event shall reflect, 
26    and be subject to, the following terms, requirements, and 
 
 
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1    limitations:
2            (i) Contracts are for delivery of carbon 
3        mitigation credits, and are not energy or capacity 
4        sales contracts requiring physical delivery. Pursuant 
5        to item (iii), contract payments shall fully deduct 
6        the value of any monetized federal production tax 
7        credits, credits issued pursuant to a federal clean 
8        energy standard, and other federal credits if 
9        applicable.
10            (ii) Contracts for carbon mitigation credits shall 
11        commence with the delivery year beginning on June 1, 
12        2022 and shall be for a term of 5 delivery years 
13        concluding on May 31, 2027.
14            (iii) The price per carbon mitigation credit to be 
15        paid under a contract for a given delivery year shall 
16        be equal to an accepted bid price less the sum of:
17                (I) one of the following energy price indices, 
18            selected by the bidder at the time of the bid for 
19            the term of the contract:
20                    (aa) the weighted-average hourly day-ahead 
21                price for the applicable delivery year at the 
22                busbar of all resources procured pursuant to 
23                this subsection (d-10), weighted by actual 
24                production from the resources; or
25                    (bb) the projected energy price for the 
26                PJM Interconnection, LLC Northern Illinois Hub 
 
 
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1                for the applicable delivery year determined 
2                according to subitem (aa) of item (iii) of 
3                subparagraph (B) of paragraph (1) of 
4                subsection (d-5).
5                (II) the Base Residual Auction Capacity Price 
6            for the ComEd zone as determined by PJM 
7            Interconnection, LLC, divided by 24 hours per day, 
8            for the applicable delivery year for the first 3 
9            delivery years, and then any subsequent delivery 
10            years unless the PJM Interconnection, LLC applies 
11            the Minimum Offer Price Rule to participating 
12            carbon-free energy resources because they supply 
13            carbon mitigation credits pursuant to this Section 
14            at which time, upon notice by the carbon-free 
15            energy resource to the Commission and subject to 
16            the Commission's confirmation, the value under 
17            this subitem shall be zero, as further described 
18            in the carbon mitigation credit procurement plan; 
19            and
20                (III) any value of monetized federal tax 
21            credits, direct payments, or similar subsidy 
22            provided to the carbon-free energy resource from 
23            any unit of government that is not already 
24            reflected in energy prices.
25            If the price-per-megawatt-hour calculation 
26        performed under item (iii) of this subparagraph (C) 
 
 
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1        for a given delivery year results in a net positive 
2        value, then the electric utility counterparty to the 
3        contract shall multiply such net value by the 
4        applicable contract quantity and remit the amount to 
5        the supplier.
6            To protect retail customers from retail rate 
7        impacts that may arise upon the initiation of carbon 
8        policy changes, if the price-per-megawatt-hour 
9        calculation performed under item (iii) of this 
10        subparagraph (C) for a given delivery year results in 
11        a net negative value, then the supplier counterparty 
12        to the contract shall multiply such net value by the 
13        applicable contract quantity and remit such amount to 
14        the electric utility counterparty. The electric 
15        utility shall reflect such amounts remitted by 
16        suppliers as a credit on its retail customer bills as 
17        soon as practicable.
18            (iv) To ensure that retail customers in Northern 
19        Illinois do not pay more for carbon mitigation credits 
20        than the value such credits provide, and 
21        notwithstanding the provisions of this subsection 
22        (d-10), the Agency shall not accept bids for contracts 
23        that exceed a customer protection cap equal to the 
24        baseline costs of carbon-free energy resources.
25            The baseline costs for the applicable year shall 
26        be the following:
 
 
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1                (I) For the delivery year beginning June 1, 
2            2022, the baseline costs shall be an amount equal 
3            to $30.30 per megawatt-hour.
4                (II) For the delivery year beginning June 1, 
5            2023, the baseline costs shall be an amount equal 
6            to $32.50 per megawatt-hour.
7                (III) For the delivery year beginning June 1, 
8            2024, the baseline costs shall be an amount equal 
9            to $33.43 per megawatt-hour.
10                (IV) For the delivery year beginning June 1, 
11            2025, the baseline costs shall be an amount equal 
12            to $33.50 per megawatt-hour.
13                (V) For the delivery year beginning June 1, 
14            2026, the baseline costs shall be an amount equal 
15            to $34.50 per megawatt-hour.
16            An Environmental Protection Agency consultant 
17        forecast, included in a report issued April 14, 2021, 
18        projects that a carbon-free energy resource has the 
19        opportunity to earn on average approximately $30.28 
20        per megawatt-hour, for the sale of energy and capacity 
21        during the time period between 2022 and 2027. 
22        Therefore, the sale of carbon mitigation credits 
23        provides the opportunity to receive an additional 
24        amount per megawatt-hour in addition to the projected 
25        prices for energy and capacity.
26            Although actual energy and capacity prices may 
 
 
10400SB0025ham004- 398 -LRB104 16098 AAS 29398 a

1        vary from year-to-year, the General Assembly finds 
2        that this customer protection cap will help ensure 
3        that the cost of carbon mitigation credits will be 
4        less than its value, based upon the social cost of 
5        carbon identified in the Technical Support Document 
6        issued in February 2021 by the U.S. Interagency 
7        Working Group on Social Cost of Greenhouse Gases and 
8        the PJM Interconnection, LLC carbon dioxide marginal 
9        emission rate for 2020, and that a carbon-free energy 
10        resource receiving payment for carbon mitigation 
11        credits receives no more than necessary to keep those 
12        units in operation.
13        (D) No later than 7 days after the effective date of 
14    this amendatory Act of the 102nd General Assembly, the 
15    Agency shall publish its proposed carbon mitigation credit 
16    procurement plan. The Plan shall provide that winning bids 
17    shall be selected by taking into consideration which 
18    resources best match public interest criteria that 
19    include, but are not limited to, minimizing carbon dioxide 
20    emissions that result from electricity consumed in 
21    Illinois and minimizing sulfur dioxide, nitrogen oxide, 
22    and particulate matter emissions that adversely affect the 
23    citizens of this State. The selection of winning bids 
24    shall also take into account the incremental environmental 
25    benefits resulting from the procurement or procurements, 
26    such as any existing environmental benefits that are 
 
 
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1    preserved by a procurement held under this subsection 
2    (d-10) and would cease to exist if the procurement were 
3    not held, including the preservation of carbon-free energy 
4    resources. For those bidders having the same public 
5    interest criteria score, the relative ranking of such 
6    bidders shall be determined by price. The Plan shall 
7    describe in detail how each public interest factor shall 
8    be considered and weighted in the bid selection process to 
9    ensure that the public interest criteria are applied to 
10    the procurement. The Plan shall, to the extent practical 
11    and permissible by federal law, ensure that successful 
12    bidders make commercially reasonable efforts to apply for 
13    federal tax credits, direct payments, or similar subsidy 
14    programs that support carbon-free generation and for which 
15    the successful bidder is eligible. Upon publishing of the 
16    carbon mitigation credit procurement plan, copies of the 
17    plan shall be posted and made publicly available on the 
18    Agency's website. All interested parties shall have 7 days 
19    following the date of posting to provide comment to the 
20    Agency on the plan. All comments shall be posted to the 
21    Agency's website. Following the end of the comment period, 
22    but no more than 19 days later than the effective date of 
23    this amendatory Act of the 102nd General Assembly, the 
24    Agency shall revise the plan as necessary based on the 
25    comments received and file its carbon mitigation credit 
26    procurement plan with the Commission.
 
 
10400SB0025ham004- 400 -LRB104 16098 AAS 29398 a

1        (E) If the Commission determines that the plan is 
2    likely to result in the procurement of cost-effective 
3    carbon mitigation credits, then the Commission shall, 
4    after notice and hearing and opportunity for comment, but 
5    no later than 42 days after the Agency filed the plan, 
6    approve the plan or approve it with modification. For 
7    purposes of this subsection (d-10), "cost-effective" means 
8    carbon mitigation credits that are procured from 
9    carbon-free energy resources at prices that are within the 
10    limits specified in this paragraph (3). As part of the 
11    Commission's review and acceptance or rejection of the 
12    procurement results, the Commission shall, in its public 
13    notice of successful bidders:
14            (i) identify how the selected carbon-free energy 
15        resources satisfy the public interest criteria 
16        described in this paragraph (3) of minimizing carbon 
17        dioxide emissions that result from electricity 
18        consumed in Illinois and minimizing sulfur dioxide, 
19        nitrogen oxide, and particulate matter emissions that 
20        adversely affect the citizens of this State;
21            (ii) specifically address how the selection of 
22        carbon-free energy resources takes into account the 
23        incremental environmental benefits resulting from the 
24        procurement, including any existing environmental 
25        benefits that are preserved by the procurements held 
26        under this amendatory Act of the 102nd General 
 
 
10400SB0025ham004- 401 -LRB104 16098 AAS 29398 a

1        Assembly and would have ceased to exist if the 
2        procurements had not been held, such as the 
3        preservation of carbon-free energy resources;
4            (iii) quantify the environmental benefit of 
5        preserving the carbon-free energy resources procured 
6        pursuant to this subsection (d-10), including the 
7        following:
8                (I) an assessment value of avoided greenhouse 
9            gas emissions measured as the product of the 
10            carbon-free energy resources' output over the 
11            contract term, using generally accepted 
12            methodologies for the valuation of avoided 
13            emissions; and
14                (II) an assessment of costs of replacement 
15            with other carbon-free energy resources and 
16            renewable energy resources, including wind and 
17            photovoltaic generation, based upon an assessment 
18            of the prices paid for renewable energy credits 
19            through programs and procurements conducted 
20            pursuant to subsection (c) of Section 1-75 of this 
21            Act, and the additional storage necessary to 
22            produce the same or similar capability of matching 
23            customer usage patterns.
24        (F) The procurements described in this paragraph (3), 
25    including, but not limited to, the execution of all 
26    contracts procured, shall be completed no later than 
 
 
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1    December 3, 2021. The procurement and plan approval 
2    processes required by this paragraph (3) shall be 
3    conducted in conjunction with the procurement and plan 
4    approval processes required by Section 16-111.5 of the 
5    Public Utilities Act, to the extent practicable. However, 
6    the Agency and Commission may, as appropriate, modify the 
7    various dates and timelines under this subparagraph and 
8    subparagraphs (D) and (E) of this paragraph (3) to meet 
9    the December 3, 2021 contract execution deadline. 
10    Following the completion of such procurements, and 
11    consistent with this paragraph (3), the Agency shall 
12    calculate the payments to be made under each contract in a 
13    timely fashion.
14        (F-1) Costs incurred by the electric utility pursuant 
15    to a contract authorized by this subsection (d-10) shall 
16    be deemed prudently incurred and reasonable in amount, and 
17    the electric utility shall be entitled to full cost 
18    recovery pursuant to a tariff or tariffs filed with the 
19    Commission.
20        (G) The counterparty electric utility shall retire all 
21    carbon mitigation credits used to comply with the 
22    requirements of this subsection (d-10).
23        (H) If a carbon-free energy resource is sold to 
24    another owner, the rights, obligations, and commitments 
25    under this subsection (d-10) shall continue to the 
26    subsequent owner.
 
 
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1        (I) This subsection (d-10) shall become inoperative on 
2    January 1, 2028.
3    (d-20) Energy storage system portfolio standard.
4        (1) The General Assembly finds that the deployment of 
5    energy storage systems is necessary to successfully 
6    integrate high levels of renewable energy, to avoid the 
7    creation and increase of carbon emissions from electric 
8    generation sources, and to ensure affordable, stable, 
9    clean, reliable, and resilient electricity.
10        (2) The Agency shall develop an energy storage system 
11    resources procurement plan that includes the competitive 
12    procurement events, procurement programs, or both, as 
13    necessary (i) to meet the goals set forth in this 
14    subsection (d-20), (ii) to meet the planning requirements 
15    established under Sections 16-201 and 16-202 of the Public 
16    Utilities Act, (iii) to meet the clean energy policy 
17    established by Public Act 102-662, and (iv) to cause 
18    electric utilities serving more than 300,000 customers in 
19    the State as of January 1, 2019 to contract for energy 
20    storage resources. The energy storage system resources 
21    procurement plan approval processes shall be conducted 
22    consistent with the processes outlined in paragraph (6) of 
23    subsection (b) of Section 16-111.5 of the Public Utilities 
24    Act, with the initial energy storage system resources 
25    procurement plan released for comment in calendar year 
26    2027. The Agency shall review and may revise the energy 
 
 
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1    storage system resources procurement plan at least every 2 
2    years. The Agency shall establish, and the Commission 
3    shall approve or approve as modified, an energy storage 
4    system resources procurement plan that includes:
5            (A) storage targets in addition to the initial 
6        procurements specified in paragraph (3) of this 
7        subsection (d-20) at levels identified through the 
8        integrated resource planning process outlined in 
9        Section 16-202 of the Public Utilities Act;
10            (B) a bid selection process that is based on the 
11        bid price, when compared with an equal energy storage 
12        duration and interconnected to the same independent 
13        system operator (ISO) or regional transmission 
14        organization (RTO), and that may provide for 
15        consideration of the following:
16                (i) the project's viability and ability to 
17            meet or exceed operational date targets;
18                (ii) the developer's experience;
19                (iii) requirements for demonstration of 
20            binding site control that are sufficient for 
21            proposed energy storage facilities;
22                (iv) the availability or dependence on any 
23            transmission expansion or upgrades needed; and
24                (v) other resource adequacy and reliability 
25            considerations;
26            (C) consideration of the need to ensure adequate, 
 
 
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1        reliable, affordable, efficient, and environmentally 
2        sustainable electric service at the lowest total cost 
3        over time;
4            (D) proposals for the financial support of energy 
5        storage systems using contract models, which may 
6        include, but are not limited to, the following:
7                (i) an indexed storage credit procurement, 
8            including payments to energy storage system owners 
9            or operators with any offsets and refunds for 
10            potential energy and capacity revenues;
11                (ii) support for energy storage system 
12            resources through contract structures that do not 
13            create contractual obligations on utilities that 
14            are not contingent on full and timely cost 
15            recovery, that avoid negative financial impacts on 
16            the utilities, and that are agreed upon by the 
17            utilities; and
18                (iii) other approaches as deemed suitable by 
19            the Agency and the Commission; and
20            (E) consideration that the Agency may include a 
21        methodology that could prioritize procurement of 
22        energy storage resources that are located in 
23        communities eligible to receive Energy Transition 
24        Community Grants pursuant to Section 10-20 of the 
25        Energy Community Reinvestment Act.    
26        In developing its procurement plan and conducting the 
 
 
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1    storage procurements outlined in this paragraph (2) and in 
2    paragraph (3), the Agency may use the services of expert 
3    consulting firms identified in paragraphs (1) and (2) of 
4    subsection (a) of this Section.
5        (3) Notwithstanding whether an energy storage system 
6    resources procurement plan has been approved, the 
7    following provisions shall apply to the Agency's initial 
8    procurement of energy storage system resources under this 
9    subsection (d-20):
10            (A) The Agency shall conduct an initial energy 
11        storage procurement on or before August 26, 2026 or 90 
12        days after the effective date of this amendatory Act 
13        of the 104th General Assembly, whichever is earlier. 
14        For the purposes of this initial energy storage 
15        procurement, the Agency shall conduct a procurement 
16        that results in electric utilities that served more 
17        than 300,000 customers in the State as of January 1, 
18        2019 contracting for at least 1,038 megawatts of 
19        cost-effective stand-alone energy storage systems that 
20        can achieve commercial operation on or before December 
21        31, 2029 or an alternative date proposed by the Agency 
22        that is no later than December 31, 2030. The 
23        procurement target shall be separated for projects 
24        interconnected within Midcontinent Independent System 
25        Operator Local Resource Zone 4 (MISO Zone 4) and for 
26        projects interconnected within the PJM 
 
 
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1        Interconnection, LLC ComEd Locational Deliverability 
2        Area (PJM ComEd Area) as follows:
3                (i) 450 megawatts in MISO Zone 4; and
4                (ii) 588 megawatts in the PJM ComEd Area.
5            For purposes of this subsection (d-20), 
6        "stand-alone" means systems that are (i) separately 
7        metered by a revenue-quality meter that satisfies the 
8        requirements of the RTO; (ii) operate independently 
9        without constraints or hindrances from other 
10        generation units; and (iii) demonstrate the ability to 
11        charge and discharge independent of any generation 
12        unit output.    
13            (B) The Agency shall conduct a series of 
14        additional energy storage procurements that result in 
15        electric utilities contracting for energy storage 
16        resources in an amount of 3,000 megawatts of 
17        cumulative energy storage capacity for projects 
18        committed to reaching commercial operation on or 
19        before December 31, 2030, or an alternative date 
20        proposed by the Agency, subject to extension for a 
21        delay due to interconnection of the energy storage 
22        system, a delay in obtaining permits necessary to 
23        build or operate the energy storage system, or other 
24        circumstances at the discretion of the Agency.
25            The additional energy storage resources 
26        procurements shall be conducted in calendar years 2027 
 
 
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1        and 2028 in a manner that ensures the quantities 
2        listed in this subparagraph (B), and as updated in the 
3        integrated resource plan approved by the Commission 
4        pursuant to Section 16-201 of the Public Utilities 
5        Act, are met in the specified timeframe. To the extent 
6        the integrated resource planning process outlined in 
7        Section 16-202 of the Public Utilities Act authorizes 
8        energy storage system procurement amounts above the 
9        amount identified in this subparagraph (B), the Agency 
10        shall conduct additional energy storage procurements 
11        in 2028, 2029, 2030, and thereafter that result in 
12        electric utilities contracting for energy storage 
13        resources at those additional identified levels. The 
14        procurements shall be conducted in a manner that 
15        maximizes projects available in the MISO and PJM 
16        queues, ensures the likelihood of project development 
17        through the development of project maturity 
18        requirements, enables sufficient competition for price 
19        competitiveness, and aligns to the extent practicable 
20        with regional transmission organization study phases. 
21        The procurements shall select projects interconnected 
22        to MISO Zone 4 and the PJM ComEd Area and shall follow 
23        either (i) a similar geographic split to the ratio of 
24        quantities established in subparagraph (A) of this 
25        paragraph (3), (ii) an alternative geographic split 
26        proposed by the Agency based on project availability 
 
 
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1        in advanced stages of the MISO and PJM queues, or (iii) 
2        that is informed by MISO and PJM planning activities, 
3        auctions, or reports that indicate capacity resource 
4        shortages or impending shortages and that reflect the 
5        assessments made through the processes outlined in 
6        subparagraph (A) of paragraph (2). The additional 
7        energy storage capacity procurements may be adjusted 
8        upward if determined necessary through the planning 
9        process outlined in Section 16-201 of the Public 
10        Utilities Act at times determined by the Commission.
11            (C) The initial energy storage resources 
12        procurement under subparagraph (A) of this paragraph 
13        (3) shall adopt a standard indexed storage credit 
14        contract modeled after the contract and follow a 
15        process modeled after the process included in the 
16        staff report submitted to the Governor, General 
17        Assembly, and Commission pursuant to subsection (g) of 
18        Section 16-135 of the Public Utilities Act on May 1, 
19        2025. In developing the procurement rules and 
20        procurement process for the initial procurement, the 
21        Agency shall provide an opportunity for comment on the 
22        indexed storage credit contract included in the May 1, 
23        2025 staff report and shall adopt modifications to the 
24        contract consistent with the process outlined in 
25        paragraph (2) of subsection (e) of Section 16-111.5 of 
26        the Public Utilities Act.
 
 
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1            (D) For the additional energy storage resources 
2        procurements conducted in accordance with subparagraph 
3        (B) of this paragraph (3), the Agency may, among other 
4        considerations, consider other contract structures if 
5        such contract structures and agreements do not create 
6        contractual obligations on utilities that are not 
7        contingent on full and timely cost recovery, avoid 
8        negative financial impacts on the utilities, and are 
9        agreed upon by the participating utility.
10            (E) The initial and additional energy storage 
11        resources procurements under this paragraph (3) shall 
12        solicit 20-year contracts.
13            (F) The Agency shall submit its proposed selection 
14        of successful bids for each procurement event pursuant 
15        to paragraphs (2) and (3) to the Commission for 
16        approval consistent with the processes outlined in 
17        Section 16-111.5 of the Public Utilities Act to the 
18        extent practicable.
19        (4) The energy storage system resources procurement 
20    plans developed by the Agency may consider alternatives to 
21    the initial and additional procurement terms described in 
22    paragraph (3) of this subsection (d-20), including, but 
23    not limited to:
24            (A) alternatives to the standard indexed storage 
25        credit contract used in the initial terms described in 
26        subparagraph (C) of paragraph (3) of this subsection 
 
 
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1        (d-20);
2            (B) energy storage systems that are not 
3        stand-alone;    
4            (C) proportionate allocations between MISO Zone 4 
5        and the PJM ComEd Area that are not based upon load 
6        share, including allocations reflecting the 
7        assessments made through the processes outlined in 
8        subparagraph (A) of paragraph (2);
9            (D) contract lengths other than 20 years;
10            (E) energy storage system durations other than 4 
11        hours; and
12            (F) energy storage systems connected to the 
13        distribution systems of the electric utilities.
14        The Agency may propose specific timelines for energy 
15    storage system resources procurements, which may differ 
16    across RTO zones, that are based in part upon a 
17    consideration of (i) the timing of the release of 
18    interconnection cost information through both MISO and PJM 
19    interconnection queue processes, (ii) factors that 
20    maximize the likelihood of successful project development, 
21    (iii) enabling sufficient competition for price 
22    competitiveness, and (iv) aligning to the extent 
23    practicable with RTO study phases.
24        (5) The Agency shall procure cost-effective energy 
25    storage credits or other contract instruments intended to 
26    facilitate the successful development of energy storage 
 
 
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1    projects. The procurement administrator shall establish 
2    confidential price benchmarks based on publicly available 
3    data on regional technology costs. Confidential price 
4    benchmarks shall be developed by the procurement 
5    administrator, in consultation with Commission staff, 
6    Agency staff, and the procurement monitor, and shall be 
7    subject to Commission review and approval. Price 
8    benchmarks shall reflect development costs, financing 
9    costs, and related costs resulting from requirements 
10    imposed through other provisions of State law. As used in 
11    this paragraph (5), "cost-effective" means a bidder's bid 
12    price that does not exceed confidential price benchmarks.
13        (6) All procurements under this subsection (d-20) 
14    shall comply with the geographic requirements in 
15    subparagraph (I) of paragraph (1) of subsection (c) of 
16    Section 1-75 and shall follow the procurement processes 
17    and procedures described in this Section and Section 
18    16-111.5 of the Public Utilities Act, to the extent 
19    practicable. The processes and procedures may be expedited 
20    to accommodate the schedule established by this Section. 
21    The Agency shall require all bidders to pay to the Agency a 
22    nonrefundable deposit determined by the Agency and no less 
23    than $10,000 per bid as practical. The Agency may also 
24    assess bidder and supplier fees to cover the cost of 
25    procurement events and develop collateral requirements to 
26    maximize the likelihood of successful project development. 
 
 
10400SB0025ham004- 413 -LRB104 16098 AAS 29398 a

1    Bidders in the initial and additional procurements 
2    described in paragraph (3) of this subsection (d-20) shall 
3    also demonstrate experience in developing to commercial 
4    readiness. As used in this paragraph (6), "developing to 
5    commercial readiness" means having notice to proceed in 
6    owning or operating energy facilities with a combined 
7    nameplate capacity of at least 100 megawatts.
8        (7) In order to advance priority access to the clean 
9    energy economy for businesses and workers from communities 
10    that have been excluded from economic opportunities in the 
11    energy sector, have been subject to disproportionate 
12    levels of pollution, and have disproportionately 
13    experienced negative public health outcomes, the Agency 
14    shall apply its equity accountability system and minimum 
15    equity standards established under subsections (c-10), 
16    (c-15), (c-20), (c-25), and (c-30) of this Section to 
17    energy storage procurement and programs and may include 
18    any proposed modifications to the equity accountability 
19    system and minimum equity standards that may be warranted 
20    with respect to energy storage resources in its plan 
21    submission to the Commission under Section 16-111.5 of the 
22    Public Utilities Act.
23        (8) Projects shall be developed in compliance with the 
24    prevailing wage and project labor agreement requirements 
25    for renewable energy projects in subparagraph (Q) of 
26    paragraph (1) of subsection (c) of Section 1-75.
 
 
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1        (9) An entity operating an energy storage facility 
2    shall demonstrate that it has entered into a labor peace 
3    agreement with a bona fide labor organization that is 
4    actively engaged in representing its employees. The labor 
5    peace agreement shall apply to the employees necessary for 
6    the ongoing maintenance and operation of the energy 
7    storage facility. The existence of a labor peace agreement 
8    shall be an ongoing material condition of an entity's 
9    authorization to maintain and operate the energy storage 
10    facility.    
11        (10) In order to promote the competitive development 
12    of energy storage systems in furtherance of the State's 
13    interest in the health, safety, and welfare of its 
14    residents, storage credits shall not be eligible to be 
15    selected under this subsection (d-20) if the energy 
16    storage resources are sourced from an energy storage 
17    system whose costs were being recovered through rates 
18    regulated by the State or any other state or states on or 
19    after January 1, 2017. No entity shall be permitted to bid 
20    unless it certifies to the Agency that it is not an 
21    electric utility, as defined in Section 16-102 of the 
22    Public Utilities Act, serving more than 10,000 customers 
23    in the State.
24        (11) The Agency shall require, as a prerequisite to 
25    payment for any storage credits, that the winning bidder 
26    provide the Agency or its designee a copy of the 
 
 
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1    interconnection agreement under which the applicable 
2    energy storage system is connected to the transmission or 
3    distribution system.
4        (12) Contracts shall provide that, if the cost 
5    recovery mechanism referenced in subsection (k) of Section 
6    16-108 of the Public Utilities Act remains in full force 
7    without amendment or the utility is otherwise authorized 
8    or entitled to full, prompt, and uninterrupted recovery of 
9    its costs through any other mechanism, then such seller 
10    shall be entitled to full, prompt, and uninterrupted 
11    payment under the applicable contract notwithstanding the 
12    application of this paragraph (12).    
13    (e) The draft procurement plans are subject to public 
14comment, as required by Section 16-111.5 of the Public 
15Utilities Act.
16    (f) The Agency shall submit the final procurement plan to 
17the Commission. The Agency shall revise a procurement plan if 
18the Commission determines that it does not meet the standards 
19set forth in Section 16-111.5 of the Public Utilities Act.
20    (g) The Agency shall assess fees to each affected utility 
21to recover the costs incurred in preparation of procurement 
22plans and in the operation of programs the annual procurement 
23plan for the utility.
24    (h) The Agency shall assess fees to each bidder to recover 
25the costs incurred in connection with a competitive 
26procurement process.
 
 
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1    (i) A renewable energy credit, carbon emission credit, 
2zero emission credit, or carbon mitigation credit can only be 
3used once to comply with a single portfolio or other standard 
4as set forth in subsection (c), subsection (d), or subsection 
5(d-5) of this Section, respectively. A renewable energy 
6credit, carbon emission credit, zero emission credit, or 
7carbon mitigation credit cannot be used to satisfy the 
8requirements of more than one standard. If more than one type 
9of credit is issued for the same megawatt hour of energy, only 
10one credit can be used to satisfy the requirements of a single 
11standard. After such use, the credit must be retired together 
12with any other credits issued for the same megawatt hour of 
13energy. 
14(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 
15103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)
 
16    (20 ILCS 3855/1-125)
17    Sec. 1-125. Agency annual reports. 
18    (a) By March February 15 of each year, the Agency shall 
19report annually to the Governor and the General Assembly on 
20the operations and transactions of the Agency. The annual 
21report shall include, but not be limited to, each of the 
22following:
23        (1) The average quantity, price, and term of all 
24    contracts for electricity procured under the procurement 
25    plans for electric utilities.
 
 
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1        (2) (Blank).
2        (3) The quantity, price, and rate impact of all energy 
3    efficiency and demand response measures purchased for 
4    electric utilities, and any measures included in the 
5    procurement plan pursuant to Section 16-111.5B of the 
6    Public Utilities Act.
7        (4) The amount of power and energy produced by each 
8    Agency facility.
9        (5) The quantity of electricity supplied by each 
10    Agency facility to municipal electric systems, 
11    governmental aggregators, or rural electric cooperatives 
12    in Illinois.
13        (6) The revenues as allocated by the Agency to each 
14    facility.
15        (7) The costs as allocated by the Agency to each 
16    facility.
17        (8) The accumulated depreciation for each facility.
18        (9) The status of any projects under development.
19        (10) Basic financial and operating information 
20    specifically detailed for the reporting year and 
21    including, but not limited to, income and expense 
22    statements, balance sheets, and changes in financial 
23    position, all in accordance with generally accepted 
24    accounting principles, debt structure, and a summary of 
25    funds on a cash basis.
26        (11) The average quantity, price, contract type and 
 
 
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1    term, and rate impact of all renewable resources procured 
2    under the long-term renewable resources procurement plans 
3    for electric utilities. 
4        (12) A comparison of the costs associated with the 
5    Agency's procurement of renewable energy resources to (A) 
6    the Agency's costs associated with electricity generated 
7    by other types of generation facilities and (B) the 
8    benefits associated with the Agency's procurement of 
9    renewable energy resources.
10        (13) An analysis of the rate impacts associated with 
11    the Illinois Power Agency's procurement of renewable 
12    resources, including, but not limited to, any long-term 
13    contracts, on the eligible retail customers of electric 
14    utilities. The analysis shall include the Agency's 
15    estimate of the total dollar impact that the Agency's 
16    procurement of renewable resources has had on the annual 
17    electricity bills of the customer classes that comprise 
18    each eligible retail customer class taking service from an 
19    electric utility.
20        (14) (Blank).
21    (b) In addition to reporting on the transactions and 
22operations of the Agency, the Agency shall also endeavor to 
23report on the following items through its annual report, 
24recognizing that full and accurate information may not be 
25available for certain items:
26        (1) The overall nameplate capacity amount of installed 
 
 
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1    and scheduled renewable energy generation capacity 
2    physically located in Illinois.
3        (2) The percentage of installed and scheduled 
4    renewable energy generation capacity as a share of overall 
5    electricity generation capacity physically located in 
6    Illinois.
7        (3) The amount of megawatt hours produced by renewable 
8    energy generation capacity physically located in Illinois 
9    for the preceding delivery year.
10        (4) The percentage of megawatt hours produced by 
11    renewable energy generation capacity physically located in 
12    Illinois as a share of overall electricity generation from 
13    facilities physically located in Illinois for the 
14    preceding delivery year and as a share of retail 
15    electricity sales in Illinois.
16        (5) The renewable portfolio standard expenditures made 
17    pursuant to paragraph (1) of subsection (c) of Section 
18    1-75 and the total scheduled and installed renewable 
19    generation capacity expected to result from these 
20    investments. This information shall include the total cost 
21    of REC delivery contracts of the renewable portfolio 
22    standard by project category, including, but not limited 
23    to, renewable energy credits delivery contracts entered 
24    into pursuant to subparagraphs (C), (G), (K), and (R) of 
25    paragraph (1) of subsection (c) Section 1-75. The Agency 
26    shall also report on the total amount of customer load 
 
 
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1    featuring renewable portfolio standard compliance 
2    obligations scheduled to be met by self-direct customers 
3    pursuant to subparagraph (R) of paragraph (1) of 
4    subsection (c) of Section 1-75, as well as the minimum 
5    annual quantities of renewable energy credits scheduled to 
6    be retired by those customers and amount of installed 
7    renewable energy generating capacity used to meet the 
8    requirements of subparagraph (R) of paragraph (1) of 
9    subsection (c) of Section 1-75.
10    The Agency may seek assistance from the Illinois Commerce 
11Commission in developing its annual report and may also retain 
12the services of its expert consulting firm used to develop its 
13procurement plans as outlined in paragraph (1) of subsection 
14(a) of Section 1-75. Confidential or commercially sensitive 
15business information provided by retail customers, alternative 
16retail electric suppliers, or other parties shall be kept 
17confidential by the Agency consistent with Section 1-120, but 
18may be publicly reported in aggregate form. 
19(Source: P.A. 102-662, eff. 9-15-21.)
 
20    Section 90-14. The State Finance Act is amended by 
21changing Sections 5.136, 5.427, and 8.3 as follows:
 
22    (30 ILCS 105/5.136)
23    Sec. 5.136. The Low-Level Radioactive Waste Facility 
24Development and Operation Fund.
 
 
10400SB0025ham004- 421 -LRB104 16098 AAS 29398 a

1(Source: P.A. 99-933, eff. 1-27-17.)
 
2    (30 ILCS 105/5.427)
3    Sec. 5.427. The Electric Vehicle Rebate and Charging Fund. 
4(Source: P.A. 102-662, eff. 9-15-21.)
 
5    (30 ILCS 105/8.3)
6    Sec. 8.3. Money in the Road Fund shall, if and when the 
7State of Illinois incurs any bonded indebtedness for the 
8construction of permanent highways, be set aside and used for 
9the purpose of paying and discharging annually the principal 
10and interest on that bonded indebtedness then due and payable, 
11and for no other purpose. The surplus, if any, in the Road Fund 
12after the payment of principal and interest on that bonded 
13indebtedness then annually due shall be used as follows:
14        first -- to pay the cost of administration of Chapters 
15    2 through 10 of the Illinois Vehicle Code, except the cost 
16    of administration of Articles I and II of Chapter 3 of that 
17    Code, and to pay the costs of the Executive Ethics 
18    Commission for oversight and administration of the Chief 
19    Procurement Officer appointed under paragraph (2) of 
20    subsection (a) of Section 10-20 of the Illinois 
21    Procurement Code for transportation; and
22        secondly -- for expenses of the Department of 
23    Transportation for construction, reconstruction, 
24    improvement, repair, maintenance, operation, and 
 
 
10400SB0025ham004- 422 -LRB104 16098 AAS 29398 a

1    administration of highways in accordance with the 
2    provisions of laws relating thereto, or for any purpose 
3    related or incident to and connected therewith, including 
4    the separation of grades of those highways with railroads 
5    and with highways and including the payment of awards made 
6    by the Illinois Workers' Compensation Commission under the 
7    terms of the Workers' Compensation Act or Workers' 
8    Occupational Diseases Act for injury or death of an 
9    employee of the Division of Highways in the Department of 
10    Transportation; or for the acquisition of land and the 
11    erection of buildings for highway purposes, including the 
12    acquisition of highway right-of-way or for investigations 
13    to determine the reasonably anticipated future highway 
14    needs; or for making of surveys, plans, specifications and 
15    estimates for and in the construction and maintenance of 
16    flight strips and of highways necessary to provide access 
17    to military and naval reservations, to defense industries 
18    and defense-industry sites, and to the sources of raw 
19    materials and for replacing existing highways and highway 
20    connections shut off from general public use at military 
21    and naval reservations and defense-industry sites, or for 
22    the purchase of right-of-way, except that the State shall 
23    be reimbursed in full for any expense incurred in building 
24    the flight strips; or for the operating and maintaining of 
25    highway garages; or for patrolling and policing the public 
26    highways and conserving the peace; or for the operating 
 
 
10400SB0025ham004- 423 -LRB104 16098 AAS 29398 a

1    expenses of the Department relating to the administration 
2    of public transportation programs; or, during fiscal year 
3    2024, for the purposes of a grant not to exceed $9,108,400 
4    to the Regional Transportation Authority on behalf of PACE 
5    for the purpose of ADA/Para-transit expenses; or, during 
6    fiscal year 2025, for the purposes of a grant not to exceed 
7    $10,020,000 to the Regional Transportation Authority on 
8    behalf of PACE for the purpose of ADA/Para-transit 
9    expenses; or for any of those purposes or any other 
10    purpose that may be provided by law.
11    Appropriations for any of those purposes are payable from 
12the Road Fund. Appropriations may also be made from the Road 
13Fund for the administrative expenses of any State agency that 
14are related to motor vehicles or arise from the use of motor 
15vehicles.
16    Beginning with fiscal year 1980 and thereafter, no Road 
17Fund monies shall be appropriated to the following Departments 
18or agencies of State government for administration, grants, or 
19operations; but this limitation is not a restriction upon 
20appropriating for those purposes any Road Fund monies that are 
21eligible for federal reimbursement:
22        1. Department of Public Health;
23        2. Department of Transportation, only with respect to 
24    subsidies for one-half fare Student Transportation and 
25    Reduced Fare for Elderly, except fiscal year 2024 when no 
26    more than $19,063,500 may be expended and except fiscal 
 
 
10400SB0025ham004- 424 -LRB104 16098 AAS 29398 a

1    year 2025 when no more than $20,969,900 may be expended;
2        3. Department of Central Management Services, except 
3    for expenditures incurred for group insurance premiums of 
4    appropriate personnel;
5        4. Judicial Systems and Agencies.
6    Beginning with fiscal year 1981 and thereafter, no Road 
7Fund monies shall be appropriated to the following Departments 
8or agencies of State government for administration, grants, or 
9operations; but this limitation is not a restriction upon 
10appropriating for those purposes any Road Fund monies that are 
11eligible for federal reimbursement:
12        1. Illinois State Police, except for expenditures with 
13    respect to the Division of Patrol and Division of Criminal 
14    Investigation;
15        2. Department of Transportation, only with respect to 
16    Intercity Rail Subsidies, except fiscal year 2024 when no 
17    more than $60,000,000 may be expended and except fiscal 
18    year 2025 when no more than $67,000,000 may be expended, 
19    and Rail Freight Services.
20    Beginning with fiscal year 1982 and thereafter, no Road 
21Fund monies shall be appropriated to the following Departments 
22or agencies of State government for administration, grants, or 
23operations; but this limitation is not a restriction upon 
24appropriating for those purposes any Road Fund monies that are 
25eligible for federal reimbursement: Department of Central 
26Management Services, except for awards made by the Illinois 
 
 
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1Workers' Compensation Commission under the terms of the 
2Workers' Compensation Act or Workers' Occupational Diseases 
3Act for injury or death of an employee of the Division of 
4Highways in the Department of Transportation.
5    Beginning with fiscal year 1984 and thereafter, no Road 
6Fund monies shall be appropriated to the following Departments 
7or agencies of State government for administration, grants, or 
8operations; but this limitation is not a restriction upon 
9appropriating for those purposes any Road Fund monies that are 
10eligible for federal reimbursement:
11        1. Illinois State Police, except not more than 40% of 
12    the funds appropriated for the Division of Patrol and 
13    Division of Criminal Investigation;
14        2. State Officers.
15    Beginning with fiscal year 1984 and thereafter, no Road 
16Fund monies shall be appropriated to any Department or agency 
17of State government for administration, grants, or operations 
18except as provided hereafter; but this limitation is not a 
19restriction upon appropriating for those purposes any Road 
20Fund monies that are eligible for federal reimbursement. It 
21shall not be lawful to circumvent the above appropriation 
22limitations by governmental reorganization or other methods. 
23Appropriations shall be made from the Road Fund only in 
24accordance with the provisions of this Section.
25    Money in the Road Fund shall, if and when the State of 
26Illinois incurs any bonded indebtedness for the construction 
 
 
10400SB0025ham004- 426 -LRB104 16098 AAS 29398 a

1of permanent highways, be set aside and used for the purpose of 
2paying and discharging during each fiscal year the principal 
3and interest on that bonded indebtedness as it becomes due and 
4payable as provided in the General Obligation Bond Act, and 
5for no other purpose. The surplus, if any, in the Road Fund 
6after the payment of principal and interest on that bonded 
7indebtedness then annually due shall be used as follows:
8        first -- to pay the cost of administration of Chapters 
9    2 through 10 of the Illinois Vehicle Code; and
10        secondly -- no Road Fund monies derived from fees, 
11    excises, or license taxes relating to registration, 
12    operation and use of vehicles on public highways or to 
13    fuels used for the propulsion of those vehicles, shall be 
14    appropriated or expended other than for costs of 
15    administering the laws imposing those fees, excises, and 
16    license taxes, statutory refunds and adjustments allowed 
17    thereunder, administrative costs of the Department of 
18    Transportation, including, but not limited to, the 
19    operating expenses of the Department relating to the 
20    administration of public transportation programs, payment 
21    of debts and liabilities incurred in construction and 
22    reconstruction of public highways and bridges, acquisition 
23    of rights-of-way for and the cost of construction, 
24    reconstruction, maintenance, repair, and operation of 
25    public highways and bridges under the direction and 
26    supervision of the State, political subdivision, or 
 
 
10400SB0025ham004- 427 -LRB104 16098 AAS 29398 a

1    municipality collecting those monies, or during fiscal 
2    year 2024 for the purposes of a grant not to exceed 
3    $9,108,400 to the Regional Transportation Authority on 
4    behalf of PACE for the purpose of ADA/Para-transit 
5    expenses, or during fiscal year 2025 for the purposes of a 
6    grant not to exceed $10,020,000 to the Regional 
7    Transportation Authority on behalf of PACE for the purpose 
8    of ADA/Para-transit expenses, and the costs for patrolling 
9    and policing the public highways (by the State, political 
10    subdivision, or municipality collecting that money) for 
11    enforcement of traffic laws. The separation of grades of 
12    such highways with railroads and costs associated with 
13    protection of at-grade highway and railroad crossing shall 
14    also be permissible.
15    Appropriations for any of such purposes are payable from 
16the Road Fund or the Grade Crossing Protection Fund as 
17provided in Section 8 of the Motor Fuel Tax Law.
18    Except as provided in this paragraph, beginning with 
19fiscal year 1991 and thereafter, no Road Fund monies shall be 
20appropriated to the Illinois State Police for the purposes of 
21this Section in excess of its total fiscal year 1990 Road Fund 
22appropriations for those purposes unless otherwise provided in 
23Section 5g of this Act. For fiscal years 2003, 2004, 2005, 
242006, and 2007 only, no Road Fund monies shall be appropriated 
25to the Department of State Police for the purposes of this 
26Section in excess of $97,310,000. For fiscal year 2008 only, 
 
 
10400SB0025ham004- 428 -LRB104 16098 AAS 29398 a

1no Road Fund monies shall be appropriated to the Department of 
2State Police for the purposes of this Section in excess of 
3$106,100,000. For fiscal year 2009 only, no Road Fund monies 
4shall be appropriated to the Department of State Police for 
5the purposes of this Section in excess of $114,700,000. 
6Beginning in fiscal year 2010, no Road Fund moneys shall be 
7appropriated to the Illinois State Police. It shall not be 
8lawful to circumvent this limitation on appropriations by 
9governmental reorganization or other methods unless otherwise 
10provided in Section 5g of this Act.
11    In fiscal year 1994, no Road Fund monies shall be 
12appropriated to the Secretary of State for the purposes of 
13this Section in excess of the total fiscal year 1991 Road Fund 
14appropriations to the Secretary of State for those purposes, 
15plus $9,800,000. It shall not be lawful to circumvent this 
16limitation on appropriations by governmental reorganization or 
17other method.
18    Beginning with fiscal year 1995 and thereafter, no Road 
19Fund monies shall be appropriated to the Secretary of State 
20for the purposes of this Section in excess of the total fiscal 
21year 1994 Road Fund appropriations to the Secretary of State 
22for those purposes. It shall not be lawful to circumvent this 
23limitation on appropriations by governmental reorganization or 
24other methods.
25    Beginning with fiscal year 2000, total Road Fund 
26appropriations to the Secretary of State for the purposes of 
 
 
10400SB0025ham004- 429 -LRB104 16098 AAS 29398 a

1this Section shall not exceed the amounts specified for the 
2following fiscal years:
3    Fiscal Year 2000$80,500,000;
4    Fiscal Year 2001$80,500,000;
5    Fiscal Year 2002$80,500,000;
6    Fiscal Year 2003$130,500,000;
7    Fiscal Year 2004$130,500,000;
8    Fiscal Year 2005$130,500,000; 
9    Fiscal Year 2006 $130,500,000; 
10    Fiscal Year 2007 $130,500,000; 
11    Fiscal Year 2008$130,500,000; 
12    Fiscal Year 2009 $130,500,000. 
13    For fiscal year 2010, no road fund moneys shall be 
14appropriated to the Secretary of State. 
15    Beginning in fiscal year 2011, moneys in the Road Fund 
16shall be appropriated to the Secretary of State for the 
17exclusive purpose of paying refunds due to overpayment of fees 
18related to Chapter 3 of the Illinois Vehicle Code unless 
19otherwise provided for by law. 
20    Beginning in fiscal year 2025, moneys in the Road Fund may 
21be appropriated to the Environmental Protection Agency for the 
22exclusive purpose of making deposits into the Electric Vehicle 
23Rebate and Charging Fund, subject to appropriation, to be used 
24for purposes consistent with Section 11 of Article IX of the 
25Illinois Constitution. 
26    It shall not be lawful to circumvent this limitation on 
 
 
10400SB0025ham004- 430 -LRB104 16098 AAS 29398 a

1appropriations by governmental reorganization or other 
2methods.
3    No new program may be initiated in fiscal year 1991 and 
4thereafter that is not consistent with the limitations imposed 
5by this Section for fiscal year 1984 and thereafter, insofar 
6as appropriation of Road Fund monies is concerned.
7    Nothing in this Section prohibits transfers from the Road 
8Fund to the State Construction Account Fund under Section 5e 
9of this Act; nor to the General Revenue Fund, as authorized by 
10Public Act 93-25.
11    The additional amounts authorized for expenditure in this 
12Section by Public Acts 92-0600, 93-0025, 93-0839, and 94-91 
13shall be repaid to the Road Fund from the General Revenue Fund 
14in the next succeeding fiscal year that the General Revenue 
15Fund has a positive budgetary balance, as determined by 
16generally accepted accounting principles applicable to 
17government.
18    The additional amounts authorized for expenditure by the 
19Secretary of State and the Department of State Police in this 
20Section by Public Act 94-91 shall be repaid to the Road Fund 
21from the General Revenue Fund in the next succeeding fiscal 
22year that the General Revenue Fund has a positive budgetary 
23balance, as determined by generally accepted accounting 
24principles applicable to government.
25(Source: P.A. 102-16, eff. 6-17-21; 102-538, eff. 8-20-21; 
26102-699, eff. 4-19-22; 102-813, eff. 5-13-22; 103-8, eff. 
 
 
10400SB0025ham004- 431 -LRB104 16098 AAS 29398 a

16-7-23; 103-34, eff. 1-1-24; 103-588, eff. 6-5-24; 103-605, 
2eff. 7-1-24; 103-616, eff. 7-1-24; revised 8-5-24.)
 
3    Section 90-15. The Illinois Procurement Code is amended by 
4changing Sections 1-10 and 30-20 as follows:
 
5    (30 ILCS 500/1-10)
6    Sec. 1-10. Application. 
7    (a) This Code applies only to procurements for which 
8bidders, offerors, potential contractors, or contractors were 
9first solicited on or after July 1, 1998. This Code shall not 
10be construed to affect or impair any contract, or any 
11provision of a contract, entered into based on a solicitation 
12prior to the implementation date of this Code as described in 
13Article 99, including, but not limited to, any covenant 
14entered into with respect to any revenue bonds or similar 
15instruments. All procurements for which contracts are 
16solicited between the effective date of Articles 50 and 99 and 
17July 1, 1998 shall be substantially in accordance with this 
18Code and its intent.
19    (b) This Code shall apply regardless of the source of the 
20funds with which the contracts are paid, including federal 
21assistance moneys. This Code shall not apply to:
22        (1) Contracts between the State and its political 
23    subdivisions or other governments, or between State 
24    governmental bodies, except as specifically provided in 
 
 
10400SB0025ham004- 432 -LRB104 16098 AAS 29398 a

1    this Code.
2        (2) Grants, except for the filing requirements of 
3    Section 20-80.
4        (3) Purchase of care, except as provided in Section 
5    5-30.6 of the Illinois Public Aid Code and this Section.
6        (4) Hiring of an individual as an employee and not as 
7    an independent contractor, whether pursuant to an 
8    employment code or policy or by contract directly with 
9    that individual.
10        (5) Collective bargaining contracts.
11        (6) Purchase of real estate, except that notice of 
12    this type of contract with a value of more than $25,000 
13    must be published in the Procurement Bulletin within 10 
14    calendar days after the deed is recorded in the county of 
15    jurisdiction. The notice shall identify the real estate 
16    purchased, the names of all parties to the contract, the 
17    value of the contract, and the effective date of the 
18    contract.
19        (7) Contracts necessary to prepare for anticipated 
20    litigation, enforcement actions, or investigations, 
21    provided that the chief legal counsel to the Governor 
22    shall give his or her prior approval when the procuring 
23    agency is one subject to the jurisdiction of the Governor, 
24    and provided that the chief legal counsel of any other 
25    procuring entity subject to this Code shall give his or 
26    her prior approval when the procuring entity is not one 
 
 
10400SB0025ham004- 433 -LRB104 16098 AAS 29398 a

1    subject to the jurisdiction of the Governor.
2        (8) (Blank).
3        (9) Procurement expenditures by the Illinois 
4    Conservation Foundation when only private funds are used.
5        (10) (Blank). 
6        (11) Public-private agreements entered into according 
7    to the procurement requirements of Section 20 of the 
8    Public-Private Partnerships for Transportation Act and 
9    design-build agreements entered into according to the 
10    procurement requirements of Section 25 of the 
11    Public-Private Partnerships for Transportation Act.
12        (12) (A) Contracts for legal, financial, and other 
13    professional and artistic services entered into by the 
14    Illinois Finance Authority in which the State of Illinois 
15    is not obligated. Such contracts shall be awarded through 
16    a competitive process authorized by the members of the 
17    Illinois Finance Authority and are subject to Sections 
18    5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, 
19    as well as the final approval by the members of the 
20    Illinois Finance Authority of the terms of the contract.
21        (B) Contracts for legal and financial services entered 
22    into by the Illinois Housing Development Authority in 
23    connection with the issuance of bonds in which the State 
24    of Illinois is not obligated. Such contracts shall be 
25    awarded through a competitive process authorized by the 
26    members of the Illinois Housing Development Authority and 
 
 
10400SB0025ham004- 434 -LRB104 16098 AAS 29398 a

1    are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, 
2    and 50-37 of this Code, as well as the final approval by 
3    the members of the Illinois Housing Development Authority 
4    of the terms of the contract. 
5        (13) Contracts for services, commodities, and 
6    equipment to support the delivery of timely forensic 
7    science services in consultation with and subject to the 
8    approval of the Chief Procurement Officer as provided in 
9    subsection (d) of Section 5-4-3a of the Unified Code of 
10    Corrections, except for the requirements of Sections 
11    20-60, 20-65, 20-70, and 20-160 and Article 50 of this 
12    Code; however, the Chief Procurement Officer may, in 
13    writing with justification, waive any certification 
14    required under Article 50 of this Code. For any contracts 
15    for services which are currently provided by members of a 
16    collective bargaining agreement, the applicable terms of 
17    the collective bargaining agreement concerning 
18    subcontracting shall be followed.
19        On and after January 1, 2019, this paragraph (13), 
20    except for this sentence, is inoperative. 
21        (14) Contracts for participation expenditures required 
22    by a domestic or international trade show or exhibition of 
23    an exhibitor, member, or sponsor.
24        (15) Contracts with a railroad or utility that 
25    requires the State to reimburse the railroad or utilities 
26    for the relocation of utilities for construction or other 
 
 
10400SB0025ham004- 435 -LRB104 16098 AAS 29398 a

1    public purpose. Contracts included within this paragraph 
2    (15) shall include, but not be limited to, those 
3    associated with: relocations, crossings, installations, 
4    and maintenance. For the purposes of this paragraph (15), 
5    "railroad" means any form of non-highway ground 
6    transportation that runs on rails or electromagnetic 
7    guideways and "utility" means: (1) public utilities as 
8    defined in Section 3-105 of the Public Utilities Act, (2) 
9    telecommunications carriers as defined in Section 13-202 
10    of the Public Utilities Act, (3) electric cooperatives as 
11    defined in Section 3.4 of the Electric Supplier Act, (4) 
12    telephone or telecommunications cooperatives as defined in 
13    Section 13-212 of the Public Utilities Act, (5) rural 
14    water or waste water systems with 10,000 connections or 
15    less, (6) a holder as defined in Section 21-201 of the 
16    Public Utilities Act, and (7) municipalities owning or 
17    operating utility systems consisting of public utilities 
18    as that term is defined in Section 11-117-2 of the 
19    Illinois Municipal Code. 
20        (16) Procurement expenditures necessary for the 
21    Department of Public Health to provide the delivery of 
22    timely newborn screening services in accordance with the 
23    Newborn Metabolic Screening Act. 
24        (17) Procurement expenditures necessary for the 
25    Department of Agriculture, the Department of Financial and 
26    Professional Regulation, the Department of Human Services, 
 
 
10400SB0025ham004- 436 -LRB104 16098 AAS 29398 a

1    and the Department of Public Health to implement the 
2    Compassionate Use of Medical Cannabis Program and Opioid 
3    Alternative Pilot Program requirements and ensure access 
4    to medical cannabis for patients with debilitating medical 
5    conditions in accordance with the Compassionate Use of 
6    Medical Cannabis Program Act.
7        (18) This Code does not apply to any procurements 
8    necessary for the Department of Agriculture, the 
9    Department of Financial and Professional Regulation, the 
10    Department of Human Services, the Department of Commerce 
11    and Economic Opportunity, and the Department of Public 
12    Health to implement the Cannabis Regulation and Tax Act if 
13    the applicable agency has made a good faith determination 
14    that it is necessary and appropriate for the expenditure 
15    to fall within this exemption and if the process is 
16    conducted in a manner substantially in accordance with the 
17    requirements of Sections 20-160, 25-60, 30-22, 50-5, 
18    50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35, 
19    50-36, 50-37, 50-38, and 50-50 of this Code; however, for 
20    Section 50-35, compliance applies only to contracts or 
21    subcontracts over $100,000. Notice of each contract 
22    entered into under this paragraph (18) that is related to 
23    the procurement of goods and services identified in 
24    paragraph (1) through (9) of this subsection shall be 
25    published in the Procurement Bulletin within 14 calendar 
26    days after contract execution. The Chief Procurement 
 
 
10400SB0025ham004- 437 -LRB104 16098 AAS 29398 a

1    Officer shall prescribe the form and content of the 
2    notice. Each agency shall provide the Chief Procurement 
3    Officer, on a monthly basis, in the form and content 
4    prescribed by the Chief Procurement Officer, a report of 
5    contracts that are related to the procurement of goods and 
6    services identified in this subsection. At a minimum, this 
7    report shall include the name of the contractor, a 
8    description of the supply or service provided, the total 
9    amount of the contract, the term of the contract, and the 
10    exception to this Code utilized. A copy of any or all of 
11    these contracts shall be made available to the Chief 
12    Procurement Officer immediately upon request. The Chief 
13    Procurement Officer shall submit a report to the Governor 
14    and General Assembly no later than November 1 of each year 
15    that includes, at a minimum, an annual summary of the 
16    monthly information reported to the Chief Procurement 
17    Officer. This exemption becomes inoperative 5 years after 
18    June 25, 2019 (the effective date of Public Act 101-27).
19        (19) Acquisition of modifications or adjustments, 
20    limited to assistive technology devices and assistive 
21    technology services, adaptive equipment, repairs, and 
22    replacement parts to provide reasonable accommodations (i) 
23    that enable a qualified applicant with a disability to 
24    complete the job application process and be considered for 
25    the position such qualified applicant desires, (ii) that 
26    modify or adjust the work environment to enable a 
 
 
10400SB0025ham004- 438 -LRB104 16098 AAS 29398 a

1    qualified current employee with a disability to perform 
2    the essential functions of the position held by that 
3    employee, (iii) to enable a qualified current employee 
4    with a disability to enjoy equal benefits and privileges 
5    of employment as are enjoyed by other similarly situated 
6    employees without disabilities, and (iv) that allow a 
7    customer, client, claimant, or member of the public 
8    seeking State services full use and enjoyment of and 
9    access to its programs, services, or benefits. 
10        For purposes of this paragraph (19):
11        "Assistive technology devices" means any item, piece 
12    of equipment, or product system, whether acquired 
13    commercially off the shelf, modified, or customized, that 
14    is used to increase, maintain, or improve functional 
15    capabilities of individuals with disabilities.
16        "Assistive technology services" means any service that 
17    directly assists an individual with a disability in 
18    selection, acquisition, or use of an assistive technology 
19    device.
20        "Qualified" has the same meaning and use as provided 
21    under the federal Americans with Disabilities Act when 
22    describing an individual with a disability. 
23        (20) Procurement expenditures necessary for the 
24    Illinois Commerce Commission to hire third-party 
25    facilitators pursuant to Sections 16-105.17 and 16-108.18 
26    of the Public Utilities Act or an ombudsman pursuant to 
 
 
10400SB0025ham004- 439 -LRB104 16098 AAS 29398 a

1    Section 16-107.5 of the Public Utilities Act, a 
2    facilitator pursuant to Section 16-105.17 of the Public 
3    Utilities Act, or a grid auditor pursuant to Section 
4    16-105.10 of the Public Utilities Act, a facilitator, 
5    expert, or consultant pursuant to Sections 16-126.2 and 
6    16-202 of the Public Utilities Act, a procurement monitor 
7    pursuant to Section 16-111.5 of the Public Utilities Act, 
8    an ombudsperson pursuant to Section 20-145 of the Public 
9    Utilities Act, or consultants and experts pursuant to 
10    Section 5-15 of the Utility Data Access Act. 
11        (21) Procurement expenditures for the purchase, 
12    renewal, and expansion of software, software licenses, or 
13    software maintenance agreements that support the efforts 
14    of the Illinois State Police to enforce, regulate, and 
15    administer the Firearm Owners Identification Card Act, the 
16    Firearm Concealed Carry Act, the Firearms Restraining 
17    Order Act, the Firearm Dealer License Certification Act, 
18    the Law Enforcement Agencies Data System (LEADS), the 
19    Uniform Crime Reporting Act, the Criminal Identification 
20    Act, the Illinois Uniform Conviction Information Act, and 
21    the Gun Trafficking Information Act, or establish or 
22    maintain record management systems necessary to conduct 
23    human trafficking investigations or gun trafficking or 
24    other stolen firearm investigations. This paragraph (21) 
25    applies to contracts entered into on or after January 10, 
26    2023 (the effective date of Public Act 102-1116) and the 
 
 
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1    renewal of contracts that are in effect on January 10, 
2    2023 (the effective date of Public Act 102-1116). 
3        (22) Contracts for project management services and 
4    system integration services required for the completion of 
5    the State's enterprise resource planning project. This 
6    exemption becomes inoperative 5 years after June 7, 2023 
7    (the effective date of the changes made to this Section by 
8    Public Act 103-8). This paragraph (22) applies to 
9    contracts entered into on or after June 7, 2023 (the 
10    effective date of the changes made to this Section by 
11    Public Act 103-8) and the renewal of contracts that are in 
12    effect on June 7, 2023 (the effective date of the changes 
13    made to this Section by Public Act 103-8). 
14        (23) Procurements necessary for the Department of 
15    Insurance to implement the Illinois Health Benefits 
16    Exchange Law if the Department of Insurance has made a 
17    good faith determination that it is necessary and 
18    appropriate for the expenditure to fall within this 
19    exemption. The procurement process shall be conducted in a 
20    manner substantially in accordance with the requirements 
21    of Sections 20-160 and 25-60 and Article 50 of this Code. A 
22    copy of these contracts shall be made available to the 
23    Chief Procurement Officer immediately upon request. This 
24    paragraph is inoperative 5 years after June 27, 2023 (the 
25    effective date of Public Act 103-103). 
26        (24) Contracts for public education programming, 
 
 
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1    noncommercial sustaining announcements, public service 
2    announcements, and public awareness and education 
3    messaging with the nonprofit trade associations of the 
4    providers of those services that inform the public on 
5    immediate and ongoing health and safety risks and hazards. 
6        (25) Procurements necessary for the Department of 
7    Early Childhood to implement the Department of Early 
8    Childhood Act if the Department has made a good faith 
9    determination that it is necessary and appropriate for the 
10    expenditure to fall within this exemption. This exemption 
11    shall only be used for products and services procured 
12    solely for use by the Department of Early Childhood. The 
13    procurements may include those necessary to design and 
14    build integrated, operational systems of programs and 
15    services. The procurements may include, but are not 
16    limited to, those necessary to align and update program 
17    standards, integrate funding systems, design and establish 
18    data and reporting systems, align and update models for 
19    technical assistance and professional development, design 
20    systems to manage grants and ensure compliance, design and 
21    implement management and operational structures, and 
22    establish new means of engaging with families, educators, 
23    providers, and stakeholders. The procurement processes 
24    shall be conducted in a manner substantially in accordance 
25    with the requirements of Article 50 (ethics) and Sections 
26    5-5 (Procurement Policy Board), 5-7 (Commission on Equity 
 
 
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1    and Inclusion), 20-80 (contract files), 20-120 
2    (subcontractors), 20-155 (paperwork), 20-160 
3    (ethics/campaign contribution prohibitions), 25-60 
4    (prevailing wage), and 25-90 (prohibited and authorized 
5    cybersecurity) of this Code. Beginning January 1, 2025, 
6    the Department of Early Childhood shall provide a 
7    quarterly report to the General Assembly detailing a list 
8    of expenditures and contracts for which the Department 
9    uses this exemption. This paragraph is inoperative on and 
10    after July 1, 2027. 
11        (26) (25) Procurements that are necessary for 
12    increasing the recruitment and retention of State 
13    employees, particularly minority candidates for 
14    employment, including: 
15            (A) procurements related to registration fees for 
16        job fairs and other outreach and recruitment events;
17            (B) production of recruitment materials; and
18            (C) other services related to recruitment and 
19        retention of State employees.
20        The exemption under this paragraph (26) (25) applies 
21    only if the State agency has made a good faith 
22    determination that it is necessary and appropriate for the 
23    expenditure to fall within this paragraph (26) (25). The 
24    procurement process under this paragraph (26) (25) shall 
25    be conducted in a manner substantially in accordance with 
26    the requirements of Sections 20-160 and 25-60 and Article 
 
 
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1    50 of this Code. A copy of these contracts shall be made 
2    available to the Chief Procurement Officer immediately 
3    upon request. Nothing in this paragraph (26) (25)    
4    authorizes the replacement or diminishment of State 
5    responsibilities in hiring or the positions that 
6    effectuate that hiring. This paragraph (26) (25) is 
7    inoperative on and after June 30, 2029. 
8    Notwithstanding any other provision of law, for contracts 
9with an annual value of more than $100,000 entered into on or 
10after October 1, 2017 under an exemption provided in any 
11paragraph of this subsection (b), except paragraph (1), (2), 
12or (5), each State agency shall post to the appropriate 
13procurement bulletin the name of the contractor, a description 
14of the supply or service provided, the total amount of the 
15contract, the term of the contract, and the exception to the 
16Code utilized. The chief procurement officer shall submit a 
17report to the Governor and General Assembly no later than 
18November 1 of each year that shall include, at a minimum, an 
19annual summary of the monthly information reported to the 
20chief procurement officer. 
21    (c) This Code does not apply to the electric power 
22procurement process provided for under Section 1-75 of the 
23Illinois Power Agency Act and Section 16-111.5 of the Public 
24Utilities Act. This Code does not apply to the procurement of 
25technical and policy experts pursuant to Section 1-129 of the 
26Illinois Power Agency Act. 
 
 
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1    (d) Except for Section 20-160 and Article 50 of this Code, 
2and as expressly required by Section 9.1 of the Illinois 
3Lottery Law, the provisions of this Code do not apply to the 
4procurement process provided for under Section 9.1 of the 
5Illinois Lottery Law. 
6    (e) This Code does not apply to the process used by the 
7Capital Development Board to retain a person or entity to 
8assist the Capital Development Board with its duties related 
9to the determination of costs of a clean coal SNG brownfield 
10facility, as defined by Section 1-10 of the Illinois Power 
11Agency Act, as required in subsection (h-3) of Section 9-220 
12of the Public Utilities Act, including calculating the range 
13of capital costs, the range of operating and maintenance 
14costs, or the sequestration costs or monitoring the 
15construction of clean coal SNG brownfield facility for the 
16full duration of construction.
17    (f) (Blank). 
18    (g) (Blank).
19    (h) This Code does not apply to the process to procure or 
20contracts entered into in accordance with Sections 11-5.2 and 
2111-5.3 of the Illinois Public Aid Code. 
22    (i) Each chief procurement officer may access records 
23necessary to review whether a contract, purchase, or other 
24expenditure is or is not subject to the provisions of this 
25Code, unless such records would be subject to attorney-client 
26privilege. 
 
 
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1    (j) This Code does not apply to the process used by the 
2Capital Development Board to retain an artist or work or works 
3of art as required in Section 14 of the Capital Development 
4Board Act. 
5    (k) This Code does not apply to the process to procure 
6contracts, or contracts entered into, by the State Board of 
7Elections or the State Electoral Board for hearing officers 
8appointed pursuant to the Election Code. 
9    (l) This Code does not apply to the processes used by the 
10Illinois Student Assistance Commission to procure supplies and 
11services paid for from the private funds of the Illinois 
12Prepaid Tuition Fund. As used in this subsection (l), "private 
13funds" means funds derived from deposits paid into the 
14Illinois Prepaid Tuition Trust Fund and the earnings thereon. 
15    (m) This Code shall apply regardless of the source of 
16funds with which contracts are paid, including federal 
17assistance moneys. Except as specifically provided in this 
18Code, this Code shall not apply to procurement expenditures 
19necessary for the Department of Public Health to conduct the 
20Healthy Illinois Survey in accordance with Section 2310-431 of 
21the Department of Public Health Powers and Duties Law of the 
22Civil Administrative Code of Illinois. 
23(Source: P.A. 102-175, eff. 7-29-21; 102-483, eff 1-1-22; 
24102-558, eff. 8-20-21; 102-600, eff. 8-27-21; 102-662, eff. 
259-15-21; 102-721, eff. 1-1-23; 102-813, eff. 5-13-22; 
26102-1116, eff. 1-10-23; 103-8, eff. 6-7-23; 103-103, eff. 
 
 
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16-27-23; 103-570, eff. 1-1-24; 103-580, eff. 12-8-23; 103-594, 
2eff. 6-25-24; 103-605, eff. 7-1-24; 103-865, eff. 1-1-25; 
3revised 11-26-24.)
 
4    (30 ILCS 500/30-20)
5    Sec. 30-20. Prequalification. 
6    (a) The Capital Development Board shall promulgate rules 
7for the development of prequalified supplier lists for 
8construction and construction-related professional services 
9and the periodic updating of those lists. Construction and 
10construction-related professional services contracts over 
11$25,000 may be awarded to any qualified suppliers.
12    (b) If deemed necessary by the Agency, the The Illinois 
13Power Agency shall promulgate rules for the development of 
14prequalified supplier lists for construction and 
15construction-related professional services and the periodic 
16updating of those lists. Construction and construction-related    
17construction related professional services contracts over 
18$25,000 may be awarded to any qualified suppliers, pursuant to 
19a competitive bidding process. 
20(Source: P.A. 95-481, eff. 8-28-07.)
 
21    Section 90-17. The Illinois Works Jobs Program Act is 
22amended by changing Section 20-15 as follows:
 
23    (30 ILCS 559/20-15)
 
 
10400SB0025ham004- 447 -LRB104 16098 AAS 29398 a

1    Sec. 20-15. Illinois Works Preapprenticeship Program; 
2Illinois Works Bid Credit Program. 
3    (a) The Illinois Works Preapprenticeship Program is 
4established and shall be administered by the Department. The 
5goal of the Illinois Works Preapprenticeship Program is to 
6create a network of community-based organizations throughout 
7the State that will recruit, prescreen, and provide 
8preapprenticeship skills training, for which participants may 
9attend free of charge and receive a stipend, to create a 
10qualified, diverse pipeline of workers who are prepared for 
11careers in the construction and building trades. Upon 
12completion of the Illinois Works Preapprenticeship Program, 
13the candidates will be skilled and work-ready. 
14    (b) There is created the Illinois Works Fund, a special 
15fund in the State treasury. The Illinois Works Fund shall be 
16administered by the Department. The Illinois Works Fund shall 
17be used to provide funding for community-based organizations 
18throughout the State. In addition to any other transfers that 
19may be provided for by law, on and after July 1, 2019 at the 
20direction of the Director of the Governor's Office of 
21Management and Budget, the State Comptroller shall direct and 
22the State Treasurer shall transfer amounts not exceeding a 
23total of $50,000,000 from the Rebuild Illinois Projects Fund 
24to the Illinois Works Fund.
25    (b-5) In addition to any other transfers that may be 
26provided for by law, beginning July 1, 2024 and each July 1 
 
 
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1thereafter, or as soon thereafter as practical, the State 
2Comptroller shall direct and the State Treasurer shall 
3transfer $27,500,000 from the Capital Projects Fund to the 
4Illinois Works Fund. 
5    (c) Each community-based organization that receives 
6funding from the Illinois Works Fund shall provide an annual 
7report to the Illinois Works Review Panel by April 1 of each 
8calendar year. The annual report shall include the following 
9information: 
10        (1) a description of the community-based 
11    organization's recruitment, screening, and training 
12    efforts; 
13        (2) the number of individuals who apply to, 
14    participate in, and complete the community-based 
15    organization's program, broken down by race, gender, age, 
16    and veteran status; and
17    (3) the number of the individuals referenced in item (2) 
18    of this subsection who are initially accepted and placed 
19    into apprenticeship programs in the construction and 
20    building trades. 
21    (d) The Department shall create and administer the 
22Illinois Works Bid Credit Program that shall provide economic 
23incentives, through bid credits, to encourage contractors and 
24subcontractors to provide contracting and employment 
25opportunities to historically underrepresented populations in 
26the construction industry. 
 
 
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1    The Illinois Works Bid Credit Program shall allow 
2contractors and subcontractors to earn bid credits for use 
3toward future bids for public works projects contracted by the 
4State or an agency of the State in order to increase the 
5chances that the contractor and the subcontractors will be 
6selected.
7    Contractors or subcontractors may be eligible to earn bid 
8credits for employing apprentices who have been verified by 
9the Department to have completed the Illinois Works 
10Preapprenticeship Program, the Climate Works Preapprenticeship 
11Program, or the Highway Construction Careers Training Program. 
12Contractors or subcontractors shall earn bid credits at a rate 
13established by the Department and based on labor hours worked 
14by apprentices who have been verified by the Department to 
15have completed the Illinois Works Preapprenticeship Program, 
16the Climate Works Preapprenticeship Program, or the Highway 
17Construction Careers Training Program. In order to earn bid 
18credits, contractors and subcontractors shall provide the 
19Department with certified payroll documenting the hours 
20performed by apprentices who have been verified by the 
21Department to have completed the Illinois Works 
22Preapprenticeship Program, the Climate Works Preapprenticeship 
23Program, or the Highway Construction Careers Training Program. 
24Contractors and subcontractors can use bid credits toward 
25future bids for public works projects contracted or funded by 
26the State or an agency of the State in order to increase the 
 
 
10400SB0025ham004- 450 -LRB104 16098 AAS 29398 a

1likelihood of being selected as the contractor for the public 
2works project toward which they have applied the bid credit. 
3The Department shall establish the rate by rule and shall 
4publish it on the Department's website. The rule may include 
5maximum bid credits allowed per contractor, per subcontractor, 
6per apprentice, per bid, or per year. 
7    The Illinois Works Credit Bank is hereby created and shall 
8be administered by the Department. The Illinois Works Credit 
9Bank shall track the bid credits. 
10    A contractor or subcontractor who has been awarded bid 
11credits under any other State program for employing 
12apprentices who have completed the Illinois Works 
13Preapprenticeship Program is not eligible to receive bid 
14credits under the Illinois Works Bid Credit Program relating 
15to the same contract.
16    The Department shall report to the Illinois Works Review 
17Panel the following: (i) the number of bid credits awarded by 
18the Department; (ii) the number of bid credits submitted by 
19the contractor or subcontractor to the agency administering 
20the public works contract; and (iii) the number of bid credits 
21accepted by the agency for such contract. Any agency that 
22awards bid credits pursuant to the Illinois Works Credit Bank 
23Program shall report to the Department the number of bid 
24credits it accepted for the public works contract.
25    Upon a finding that a contractor or subcontractor has 
26reported falsified records to the Department in order to 
 
 
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1fraudulently obtain bid credits, the Department may bar the 
2contractor or subcontractor from participating in the Illinois 
3Works Bid Credit Program and may suspend the contractor or 
4subcontractor from bidding on or participating in any public 
5works project. False or fraudulent claims for payment relating 
6to false bid credits may be subject to damages and penalties 
7under applicable law. 
8    (e) The Department shall adopt any rules deemed necessary 
9to implement this Section. In order to provide for the 
10expeditious and timely implementation of this Act, the 
11Department may adopt emergency rules. The adoption of 
12emergency rules authorized by this subsection is deemed to be 
13necessary for the public interest, safety, and welfare.
14(Source: P.A. 103-8, eff. 6-7-23; 103-305, eff. 7-28-23; 
15103-588, eff. 6-5-24; 103-605, eff. 7-1-24; 104-2, eff. 
166-16-25.)
 
17    Section 90-20. The Property Tax Code is amended by adding 
18Division 22 as follows:
 
19    (35 ILCS 200/Art. 10 Div. 22 heading new)
20
Division 22.  Commercial energy storage systems

 
21    (35 ILCS 200/10-920 new)
22    Sec. 10-920. Definitions. As used in this Division:
23    "Allowance for physical depreciation" means the product of 
 
 
10400SB0025ham004- 452 -LRB104 16098 AAS 29398 a

1the quotient that is generated by dividing the actual age in 
2years of the commercial energy storage system on the 
3assessment date by 25 years multiplied by the commercial 
4energy storage system's trended real property cost basis. 
5"Allowance for physical depreciation" may not exceed an amount 
6that reduces the value of the commercial energy storage system 
7to 30% of its trended real property cost basis or less.
8    "Commercial energy storage system" means any device or 
9assembly of devices that is (i) either installed as a 
10stand-alone system or tied to a power generation system, (ii) 
11used for the primary purpose of storing of energy for 
12wholesale or retail sale and not primarily for storage to 
13later consume on the property on which the device resides, and 
14(iii) an energy storage system, as defined in Section 16-135 
15of the Public Utilities Act.
16    "Commercial energy storage system real property cost 
17basis" means the owner of the commercial energy storage 
18system's interest in the land within the project boundaries 
19and real property improvements and shall be calculated at $65 
20per kilowatt-hour of rated kilowatt-hour energy capacity.
21    "Consumer Price Index" means the index published by the 
22Bureau of Labor Statistics of the United States Department of 
23Labor that measures the average change in prices of goods and 
24services purchased by all urban consumers, United States city 
25average, all items, 1982-84 = 100.
26    "Rated kWh energy capacity" means the maximum amount of 
 
 
10400SB0025ham004- 453 -LRB104 16098 AAS 29398 a

1stored energy in kilowatt hours. "Trended real property cost 
2basis" means the commercial energy storage system real 
3property cost basis multiplied by the trending factor.
4    "Trending factor" means the following:
5        (1) for stand-alone commercial energy storage systems, 
6    the lesser of 2% or the number generated by dividing the 
7    Consumer Price Index published by the Bureau of Labor 
8    Statistics in the December immediately preceding the 
9    assessment date by the Consumer Price Index published by 
10    the Bureau of Labor Statistics in December of 2024; or
11        (2) for commercial energy storage systems tied to a 
12    power generation system, a trending factor of 1.00.
 
13    (35 ILCS 200/10-925 new)
14    Sec. 10-925. Improvement valuation of commercial energy 
15systems. Beginning in assessment year 2026, the fair cash 
16value of commercial energy storage system improvements shall 
17be determined by subtracting the allowance for physical 
18depreciation from the commercial energy storage system trended 
19real property cost basis. Functional obsolescence and external 
20obsolescence of the commercial energy storage system 
21improvements may further reduce the fair cash value of the 
22improvements to the extent the obsolescence is proven by the 
23taxpayer by clear and convincing evidence, except that the 
24combined depreciation from all functional and economic 
25obsolescence shall not exceed 70% of the trended real property 
 
 
10400SB0025ham004- 454 -LRB104 16098 AAS 29398 a

1cost basis. The chief county assessment officer may make 
2reasonable adjustments to the actual age of the commercial 
3energy storage system to account for the routine replacement 
4or upgrade of system components.
 
5    (35 ILCS 200/10-930 new)
6    Sec. 10-930. Commercial energy storage systems; 
7equalization. Commercial energy storage systems that are 
8subject to assessment under this Division are not subject to 
9equalization factors applied by the Department, any board of 
10review, an assessor, or a chief county assessment officer.
 
11    (35 ILCS 200/10-935 new)
12    Sec. 10-935. Survey for commercial energy storage systems; 
13parcel identification numbers. Notwithstanding any other 
14provision of law, the owner of the commercial energy storage 
15system shall commission a metes and bounds survey description 
16of the land upon which the commercial energy storage system is 
17located, including access routes, over which the owner of the 
18commercial energy storage system has exclusive control. Land 
19held for future development shall not be included in the 
20project area for real property assessment purposes. The owner 
21of the commercial energy storage system shall, at the owner's 
22own expense, use a State-registered land surveyor to prepare 
23the survey. The owner of the commercial energy storage system 
24shall deliver a copy of the survey to the chief county 
 
 
10400SB0025ham004- 455 -LRB104 16098 AAS 29398 a

1assessment officer and to the owner of the land upon which the 
2commercial energy storage system is located. Upon receiving a 
3copy of the survey and an agreed acknowledgment to the 
4separate parcel identification number by the owner of the land 
5upon which the commercial energy storage system is 
6constructed, the chief county assessment officer shall issue a 
7separate parcel identification number for the real property 
8improvements, including the land containing the commercial 
9energy storage system, to be used only for the purposes of 
10property assessment for taxation. If no survey is provided, 
11the chief county assessment officer shall determine the area 
12of the site that is occupied by the commercial energy storage 
13system. The chief county assessment officer's determination 
14shall be final and may not be challenged on review by the owner 
15of the commercial energy storage system. The property records 
16shall contain the legal description of the commercial energy 
17storage system parcel and describe any leasehold interest or 
18other interest of the owner of the commercial energy storage 
19system in the property. A plat prepared under this Section 
20shall not be construed as a violation of the Plat Act.
21    Surveys that are prepared in accordance with either 
22Section 10-740 or Section 10-620 and that also include the 
23location of a commercial energy storage system in the survey's 
24metes and bounds description shall satisfy the requirements of 
25this Section.
 
 
 
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1    (35 ILCS 200/10-940 new)
2    Sec. 10-940. Real estate taxes. Notwithstanding the 
3provisions of Section 9-175 of this Code, the owner of the 
4commercial energy storage system shall be liable for the real 
5estate taxes for the land and real property improvements of 
6the commercial energy storage system. Notwithstanding the 
7foregoing, the owner of the land upon which a commercial 
8energy storage system is located may pay any unpaid tax of the 
9commercial energy storage system parcel prior to the 
10initiation of any tax sale proceedings.
 
11    (35 ILCS 200/10-945 new)
12    Sec. 10-945. Property assessed as farmland. 
13Notwithstanding any other provision of law, real property 
14assessed as farmland in accordance with Section 10-110 in the 
15assessment year prior to valuation under this Division shall 
16return to being assessed as farmland in accordance with 
17Section 10-110 in the year following completion of the removal 
18of the commercial energy storage system if the property is 
19returned to a farm use, as defined in Section 1-60, 
20notwithstanding that the land was not used for farming for the 
212 preceding years.
 
22    (35 ILCS 200/10-950 new)
23    Sec. 10-950. Abatements. Any taxing district may, upon a 
24majority vote of its governing authority and after the 
 
 
10400SB0025ham004- 457 -LRB104 16098 AAS 29398 a

1determination of the assessed valuation as set forth in this 
2Code, order the clerk of the appropriate municipality or 
3county to abate any portion of real property taxes otherwise 
4levied or extended by the taxing district on a commercial 
5energy storage system.
 
6    (35 ILCS 200/10-953 new)
7    Sec. 10-953. Cook County exemption. This Division 22 does 
8not apply to any property located within Cook County.
 
9    (35 ILCS 200/10-955 new)
10    Sec. 10-955. Applicability. The provisions of this 
11Division apply for assessment years 2026 through 2040.
 
12    Section 90-22. The Radioactive Waste Compact Enforcement 
13Act is amended by changing Section 15, 25, 30, and 31 as 
14follows:
 
15    (45 ILCS 141/15)
16    Sec. 15. Definitions. In this Act:
17    "IEMA-OHS" means the Illinois Emergency Management Agency 
18and Office of Homeland Security, or its successor agency.
19    "Commission" means the Central Midwest Interstate 
20Low-Level Radioactive Waste Commission.
21    "Compact" means the Central Midwest Interstate Low-Level 
22Radioactive Waste Compact.
 
 
10400SB0025ham004- 458 -LRB104 16098 AAS 29398 a

1    "Director" means the Director of IEMA-OHS. 
2    "Disposal" means the isolation of waste from the biosphere 
3in a permanent facility designed for that purpose.
4    "Facility" means a parcel of land or site, together with 
5the structures, equipment, and improvements on or appurtenant 
6to the land or site, that is used or is being developed for the 
7treatment, storage or disposal of low-level radioactive waste.
8    "Low-level radioactive waste" or "waste" means radioactive 
9waste not classified as (1) high-level radioactive waste, (2) 
10transuranic waste, (3) spent nuclear fuel, or (4) byproduct 
11material as defined in Sections 11e(2), 11e(3), and 11e(4) of 
12the Atomic Energy Act (42 U.S.C. 2014). This definition shall 
13apply notwithstanding any declaration by the federal 
14government, a state, or any regulatory agency that any 
15radioactive material is exempt from any regulatory control.
16    "Management plan" means the plan adopted by the Commission 
17for the storage, transportation, treatment and disposal of 
18waste within the region.
19    "Nuclear facilities" means nuclear power plants, 
20facilities housing nuclear test and research reactors, 
21facilities for the chemical conversion of uranium, and 
22facilities for the storage of spent nuclear fuel or high-level 
23radioactive waste.
24    "Nuclear power plant" or "nuclear steam-generating 
25facility" means a thermal power plant in which the energy 
26(heat) released by the fissioning of nuclear fuel is used to 
 
 
10400SB0025ham004- 459 -LRB104 16098 AAS 29398 a

1boil water to produce steam.
2    "Nuclear power reactor" means an apparatus, other than an 
3atomic weapon, designed or used to sustain nuclear fission in 
4a self-supporting chain reaction.
5    "Person" means any individual, corporation, business 
6enterprise or other legal entity, public or private, and any 
7legal successor, representative, agent or agency of that 
8individual, corporation, business enterprise, or legal entity.
9    "Region" means the geographical area of the State of 
10Illinois and the Commonwealth of Kentucky.
11    "Regional Facility" means any facility as defined in this 
12Act that is (1) located in Illinois, and (2) established by 
13Illinois pursuant to designation of Illinois as a host state 
14by the Commission.
15    "Small modular reactor" or "SMR" means an advanced nuclear 
16reactor: (1) with a rated nameplate capacity of 300 electrical 
17megawatts or less; and (2) that may be constructed and 
18operated in combination with similar reactors at a single 
19site.
20    "Storage" means the temporary holding of radioactive 
21material for treatment or disposal.
22    "Treatment" means any method, technique or process, 
23including storage for radioactive decay, designed to change 
24the physical, chemical, or biological characteristics of the 
25radioactive material in order to render the radioactive 
26material safe for transport or management, amenable to 
 
 
10400SB0025ham004- 460 -LRB104 16098 AAS 29398 a

1recovery, convertible to another usable material, or reduced 
2in volume.
3(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24.)
 
4    (45 ILCS 141/25)
5    Sec. 25. Enforcement. 
6    (a) The Agency shall adopt regulations to administer and 
7enforce the provisions of this Act. The regulations shall be 
8adopted with the consultation and cooperation of the 
9Commission.
10    Regulations adopted by the Agency under this Act shall 
11prohibit the shipment into or acceptance of waste in Illinois 
12if the shipment or acceptance would result in a violation of 
13any provision of the Compact or this Act.
14    (b) The Agency may, by regulation, impose conditions on 
15the shipment into or acceptance of waste in Illinois that the 
16Agency determines to be reasonable and necessary to enforce 
17the provisions of this Act. The conditions may include, but 
18are not limited to (i) requiring prior notification of any 
19proposed shipment or receipt of waste; (ii) requiring the 
20shipper or recipient to identify the location to which the 
21waste will be sent for disposal following treatment or storage 
22in Illinois; (iii) limiting the time that waste from outside 
23Illinois may be held in Illinois; (iv) requiring the shipper 
24or recipient to post bond or by other mechanism to assure that 
25radioactive material will not be treated, stored, or disposed 
 
 
10400SB0025ham004- 461 -LRB104 16098 AAS 29398 a

1of in Illinois in violation of any provision of this Act; (v) 
2requiring that the shipper consent to service of process 
3before shipment of waste into Illinois.
4    (c) The Agency shall, by regulation, impose a system of 
5civil penalties in accordance with the provisions of this Act. 
6Amounts recovered under these regulations shall be deposited 
7in the Low-Level Radioactive Waste Facility Development and    
8Operation Fund.
9    (d) The regulations adopted by the Agency may provide for 
10the granting of exemptions, but only upon a showing by the 
11applicant that the granting of an exemption would be 
12consistent with the Compact.
13(Source: P.A. 103-569, eff. 6-1-24.)
 
14    (45 ILCS 141/30)
15    Sec. 30. Penalties. 
16    (a) Any person who ships or receives radioactive material 
17in violation of any provision of this Act or a regulation of 
18the Agency adopted under this Act shall be subject to a civil 
19penalty not to exceed $100,000 per occurrence.
20    (b) Any person who fails to pay a civil penalty imposed by 
21regulations adopted under this Act, or any portion of the 
22penalty, shall be liable in a civil action in an amount not to 
23exceed 4 times the amount imposed and not paid.
24    (c) Any person who intentionally violates a provision of 
25subsection (a)(1), (a)(2), (a)(3), (a)(4) or (a)(6) of Section 
 
 
10400SB0025ham004- 462 -LRB104 16098 AAS 29398 a

120 of this Act shall be guilty of a Class 4 felony.
2    (d) At the request of the Agency, the Attorney General 
3shall, on behalf of the State, bring an action for the recovery 
4of any civil penalty or the prosecution of any criminal 
5offense provided for by this Act. Any civil penalties so 
6recovered shall be deposited in the Low-Level Radioactive 
7Waste Facility Development and Operation Fund.
8(Source: P.A. 95-777, eff. 8-4-08.)
 
9    (45 ILCS 141/31)
10    Sec. 31. The Agency may accept donations of money, 
11equipment, supplies, materials, and services from any person 
12for accomplishing the purposes of this Act. Any donation of 
13money shall be deposited in the Low-Level Radioactive Waste 
14Facility Development and Operation Fund and shall be expended 
15by the Agency only in accordance with the purposes of the 
16donation.
17(Source: P.A. 95-777, eff. 8-4-08.)
 
18    Section 90-27. The Counties Code is amended by adding 
19Division 5-46 and Section 5-12024 and changing Section 5-12020 
20as follows:
 
21    (55 ILCS 5/5-12020)
22    Sec. 5-12020. Commercial wind energy facilities and 
23commercial solar energy facilities. 
 
 
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1    (a) As used in this Section:
2    "Commercial solar energy facility" means a "commercial 
3solar energy system" as defined in Section 10-720 of the 
4Property Tax Code. "Commercial solar energy facility" does not 
5mean a utility-scale solar energy facility being constructed 
6at a site that was eligible to participate in a procurement 
7event conducted by the Illinois Power Agency pursuant to 
8subsection (c-5) of Section 1-75 of the Illinois Power Agency 
9Act. 
10    "Commercial wind energy facility" means a wind energy 
11conversion facility of equal or greater than 500 kilowatts in 
12total nameplate generating capacity. "Commercial wind energy 
13facility" includes a wind energy conversion facility seeking 
14an extension of a permit to construct granted by a county or 
15municipality before January 27, 2023 (the effective date of 
16Public Act 102-1123).
17    "Facility owner" means (i) a person with a direct 
18ownership interest in a commercial wind energy facility or a 
19commercial solar energy facility, or both, regardless of 
20whether the person is involved in acquiring the necessary 
21rights, permits, and approvals or otherwise planning for the 
22construction and operation of the facility, and (ii) at the 
23time the facility is being developed, a person who is acting as 
24a developer of the facility by acquiring the necessary rights, 
25permits, and approvals or by planning for the construction and 
26operation of the facility, regardless of whether the person 
 
 
10400SB0025ham004- 464 -LRB104 16098 AAS 29398 a

1will own or operate the facility.
2    "Nonparticipating property" means real property that is 
3not a participating property.
4    "Nonparticipating residence" means a residence that is 
5located on nonparticipating property and that is existing and 
6occupied on the date that an application for a permit to 
7develop the commercial wind energy facility or the commercial 
8solar energy facility is filed with the county.
9    "Occupied community building" means any one or more of the 
10following buildings that is existing and occupied on the date 
11that the application for a permit to develop the commercial 
12wind energy facility or the commercial solar energy facility 
13is filed with the county: a school, place of worship, day care 
14facility, public library, or community center.
15    "Participating property" means real property that is the 
16subject of a written agreement between a facility owner and 
17the owner of the real property that provides the facility 
18owner an easement, option, lease, or license to use the real 
19property for the purpose of constructing a commercial wind 
20energy facility, a commercial solar energy facility, or 
21supporting facilities. "Participating property" also includes 
22real property that is owned by a facility owner for the purpose 
23of constructing a commercial wind energy facility, a 
24commercial solar energy facility, or supporting facilities.
25    "Participating residence" means a residence that is 
26located on participating property and that is existing and 
 
 
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1occupied on the date that an application for a permit to 
2develop the commercial wind energy facility or the commercial 
3solar energy facility is filed with the county.
4    "Protected lands" means real property that is: 
5        (1) subject to a permanent conservation right 
6    consistent with the Real Property Conservation Rights Act; 
7    or 
8        (2) registered or designated as a nature preserve, 
9    buffer, or land and water reserve under the Illinois 
10    Natural Areas Preservation Act.
11    "Supporting facilities" means the transmission lines, 
12substations, access roads, meteorological towers, storage 
13containers, and equipment associated with the generation and 
14storage of electricity by the commercial wind energy facility 
15or commercial solar energy facility. "Supporting facilities" 
16includes energy storage systems capable of absorbing energy 
17and storing it for use at a later time, including, but not 
18limited to, batteries and other electrochemical and 
19electromechanical technologies or systems.    
20    "Wind tower" includes the wind turbine tower, nacelle, and 
21blades. 
22    (b) Notwithstanding any other provision of law or whether 
23the county has formed a zoning commission and adopted formal 
24zoning under Section 5-12007, a county may establish standards 
25for commercial wind energy facilities, commercial solar energy 
26facilities, or both. The standards may include all of the 
 
 
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1requirements specified in this Section but may not include 
2requirements for commercial wind energy facilities or 
3commercial solar energy facilities that are more restrictive 
4than specified in this Section. A county may also regulate the 
5siting of commercial wind energy facilities with standards 
6that are not more restrictive than the requirements specified 
7in this Section in unincorporated areas of the county that are 
8outside the zoning jurisdiction of a municipality and that are 
9outside the 1.5-mile radius surrounding the zoning 
10jurisdiction of a municipality. A county may also regulate the 
11siting of commercial solar energy facilities with standards 
12that are not more restrictive than the requirements specified 
13in this Section in unincorporated areas of the county that are 
14outside of the zoning jurisdiction of a municipality.    
15    (c) If a county has elected to establish standards under 
16subsection (b), before the county grants siting approval or a 
17special use permit for a commercial wind energy facility or a 
18commercial solar energy facility, or modification of an 
19approved siting or special use permit, the county board of the 
20county in which the facility is to be sited or the zoning board 
21of appeals for the county shall hold at least one public 
22hearing. The public hearing shall be conducted in accordance 
23with the Open Meetings Act and shall conclude be held not more 
24than 60 days after the filing of the application for the 
25facility. The county shall allow interested parties to a 
26special use permit an opportunity to present evidence and to 
 
 
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1cross-examine witnesses at the hearing, but the county may 
2impose reasonable restrictions on the public hearing, 
3including reasonable time limitations on the presentation of 
4evidence and the cross-examination of witnesses. The county 
5shall also allow public comment at the public hearing in 
6accordance with the Open Meetings Act. The county shall make 
7its siting and permitting decisions not more than 30 days 
8after the conclusion of the public hearing. Notice of the 
9hearing shall be published in a newspaper of general 
10circulation in the county. A facility owner must enter into an 
11agricultural impact mitigation agreement with the Department 
12of Agriculture prior to the date of the required public 
13hearing. A commercial wind energy facility owner seeking an 
14extension of a permit granted by a county prior to July 24, 
152015 (the effective date of Public Act 99-132) must enter into 
16an agricultural impact mitigation agreement with the 
17Department of Agriculture prior to a decision by the county to 
18grant the permit extension. Counties may allow test wind 
19towers or test solar energy systems to be sited without formal 
20approval by the county board.
21    (d) A county with an existing zoning ordinance in conflict 
22with this Section shall amend that zoning ordinance to be in 
23compliance with this Section within 120 days after January 27, 
242023 (the effective date of Public Act 102-1123).
25    (e) A county may require: 
26        (1) a wind tower of a commercial wind energy facility 
 
 
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1    to be sited as follows, with setback distances measured 
2    from the center of the base of the wind tower: 
 
3Setback Description           Setback Distance
 
4Occupied Community            2.1 times the maximum blade tip
5Buildings                     height of the wind tower to the
6                              nearest point on the outside
7                              wall of the structure
 
8Participating Residences      1.1 times the maximum blade tip
9                              height of the wind tower to the
10                              nearest point on the outside
11                              wall of the structure
 
12Nonparticipating Residences   2.1 times the maximum blade tip
13                              height of the wind tower to the
14                              nearest point on the outside
15                              wall of the structure
 
16Boundary Lines of             None
17Participating Property 
 
18Boundary Lines of             1.1 times the maximum blade tip
19Nonparticipating Property     height of the wind tower to the
20                              nearest point on the property
 
 
10400SB0025ham004- 469 -LRB104 16098 AAS 29398 a

1                              line of the nonparticipating
2                              property
 
3Public Road Rights-of-Way     1.1 times the maximum blade tip
4                              height of the wind tower
5                              to the center point of the
6                              public road right-of-way
 
7Overhead Communication and    1.1 times the maximum blade tip
8Electric Transmission         height of the wind tower to the
9and Distribution Facilities   nearest edge of the property
10(Not Including Overhead       line, easement, or 
11Utility Service Lines to      right-of-way 
12Individual Houses or          containing the overhead line
13Outbuildings)
 
14Overhead Utility Service      None
15Lines to Individual
16Houses or Outbuildings
 
17Fish and Wildlife Areas       2.1 times the maximum blade
18and Illinois Nature           tip height of the wind tower
19Preserve Commission           to the nearest point on the
20Protected Lands               property line of the fish and
21                              wildlife area or protected
22                              land
 
 
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1    This Section does not exempt or excuse compliance with 
2    electric facility clearances approved or required by the 
3    National Electrical Code, the The National Electrical 
4    Safety Code, the Illinois Commerce Commission, and the    
5    Federal Energy Regulatory Commission, and their designees 
6    or successors; .    
7        (2) a wind tower of a commercial wind energy facility 
8    to be sited so that industry standard computer modeling 
9    indicates that any occupied community building or 
10    nonparticipating residence will not experience more than 
11    30 hours per year of shadow flicker under planned 
12    operating conditions;
13        (3) a commercial solar energy facility to be sited as 
14    follows, with setback distances measured from the nearest 
15    edge of any above-ground component of the facility, 
16    excluding fencing: 
 
17Setback Description           Setback Distance
 
18Occupied Community            150 feet from the nearest
19Buildings and Dwellings on    point on the outside wall 
20Nonparticipating Properties   of the structure
 
21Boundary Lines of             None
22Participating Property    
 
 
 
10400SB0025ham004- 471 -LRB104 16098 AAS 29398 a

1Public Road Rights-of-Way     50 feet from the nearest
2                              edge of the public 
3                              right-of-way 
 
4Boundary Lines of             50 feet to the nearest
5Nonparticipating Property     point on the property
6                              line of the nonparticipating
7                              property
 
8        (4) a commercial solar energy facility to be sited so 
9    that the facility's perimeter is enclosed by fencing 
10    having a height of at least 6 feet and no more than 25 
11    feet; and 
12        (5) a commercial solar energy facility to be sited so 
13    that no component of a solar panel has a height of more 
14    than 20 feet above ground when the solar energy facility's 
15    arrays are at full tilt.
16    This subsection (e) shall not preclude the ability of a 
17county to require a reasonable setback distance between 
18fencing and public rights-of-way if the requirement is not 
19specific to commercial wind energy facilities or commercial 
20solar energy facilities and does not preclude the development 
21of commercial wind energy facilities or commercial solar 
22energy facilities or the ability of commercial wind energy 
23facilities or commercial solar energy facilities to comply 
24with the requirements set forth in this subsection (e).    
 
 
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1    The requirements set forth in this subsection (e) may be 
2waived subject to the written consent of the owner of each 
3affected nonparticipating property.
4    (f) A county may not set a sound limitation for wind towers 
5in commercial wind energy facilities or any components in 
6commercial solar energy facilities that is more restrictive 
7than the sound limitations established by the Illinois 
8Pollution Control Board under 35 Ill. Adm. Code Parts 900, 
9901, and 910. Additionally, in accordance with Section 25 of 
10the Environmental Protection Act, a participating property, 
11participating residence, nonparticipating property, 
12nonparticipating residence, or any combination of those 
13properties or residences may waive enforcement of the rules 
14adopted by the Illinois Pollution Control Board under 35 Ill. 
15Adm. Code Parts 900, 901, and 910 by written waiver that 
16complies with the applicable directive established in Section 
1725 of the Environmental Protection Act and is recorded in the 
18Office of the Recorder of the county in which the 
19participating property, participating residence, 
20nonparticipating property, or nonparticipating residence is 
21located. Once recorded, such a waiver shall be binding on any 
22current and future owners, residents, lessees, invitees, and 
23users of the participating property, participating residence, 
24nonparticipating property, or nonparticipating residence for 
25enforcement purposes. An owner of any participating residence 
26or nonparticipating residence shall disclose the existence of 
 
 
10400SB0025ham004- 473 -LRB104 16098 AAS 29398 a

1such a waiver to any lessee before entering any new lease for 
2the residence.    
3    A seller or transferor of a participating property, 
4participating residence, nonparticipating property, 
5nonparticipating residence, or any combination of those 
6properties or residences shall disclose the existence of such 
7a waiver to any buyer or transferee before any sale or transfer 
8of the property. If disclosure of the waiver occurs after the 
9buyer has made an offer to purchase the property, the seller 
10shall disclose the existence of the waiver before accepting 
11the buyer's offer and shall (1) allow the buyer an opportunity 
12to review the disclosure and (2) inform the buyer that the 
13buyer has the right to amend the buyer's offer.    
14    (g) A county may not place any restriction on the 
15installation or use of a commercial wind energy facility or a 
16commercial solar energy facility unless it adopts an ordinance 
17that complies with this Section. A county may not establish 
18siting standards for supporting facilities that preclude 
19development of commercial wind energy facilities or commercial 
20solar energy facilities. 
21    A request for siting approval or a special use permit for a 
22commercial wind energy facility or a commercial solar energy 
23facility, or modification of an approved siting or special use 
24permit, shall be approved if the request is in compliance with 
25the standards and conditions imposed in this Act, the zoning 
26ordinance adopted consistent with this Act Code, and the 
 
 
10400SB0025ham004- 474 -LRB104 16098 AAS 29398 a

1conditions imposed under State and federal statutes and 
2regulations. 
3    (h) A county may not adopt zoning regulations that 
4disallow, permanently or temporarily, commercial wind energy 
5facilities or commercial solar energy facilities from being 
6developed or operated in any district zoned to allow 
7agricultural or industrial uses. 
8    (i) (Blank). A county may not require permit application 
9fees for a commercial wind energy facility or commercial solar 
10energy facility that are unreasonable. All application fees 
11imposed by the county shall be consistent with fees for 
12projects in the county with similar capital value and cost.    
13    (i-5) All siting approval or special use permit 
14application fees for a commercial wind energy facility or 
15commercial solar energy facility must be reasonable. Fees that 
16do not exceed $5,000 per each megawatt of nameplate capacity 
17of the energy facility, up to a maximum of $125,000, shall be 
18considered presumptively reasonable. A county may also require 
19reimbursement from the applicant for any reasonable expenses 
20incurred by the county in processing the siting approval or 
21special use permit application in excess of the maximum fee. A 
22siting approval or special use permit shall not be subject to 
23any time deadline to start construction or obtain a building 
24permit of less than 5 years from the date of siting approval or 
25special use permit approval. A county shall allow an applicant 
26to request an extension of the deadline based upon reasonable 
 
 
10400SB0025ham004- 475 -LRB104 16098 AAS 29398 a

1cause for the extension request. The exemption shall not be 
2unreasonably withheld, conditioned, or denied.
3    (i-10) A county may require, for a commercial wind energy 
4facility or commercial solar energy facility, a single 
5building permit and a reasonable permit fee for the facility 
6which includes all supporting facilities. County building 
7permit fees for commercial wind energy facility or commercial 
8solar energy facility that do not exceed $5,000 per each 
9megawatt of nameplate capacity of the energy facility, up to a 
10maximum of $75,000, shall be considered presumptively 
11reasonable. A county may also require reimbursement from the 
12applicant for any reasonable expenses incurred by the county 
13in processing the building permit in excess of the maximum 
14fee. A county may require an applicant, upon start of 
15construction of the facility, to maintain liability insurance 
16that is commercially reasonable and consistent with prevailing 
17industry standards for similar energy facilities.
18    (j) Except as otherwise provided in this Section, a county 
19shall not require standards for construction, decommissioning, 
20or deconstruction of a commercial wind energy facility or 
21commercial solar energy facility or related financial 
22assurances that are more restrictive than those included in 
23the Department of Agriculture's standard wind farm 
24agricultural impact mitigation agreement, template 81818, or 
25standard solar agricultural impact mitigation agreement, 
26version 8.19.19, as applicable and in effect on December 31, 
 
 
10400SB0025ham004- 476 -LRB104 16098 AAS 29398 a

12022. The amount of any decommissioning payment shall be in 
2accordance with the financial assurance required by those 
3agricultural impact mitigation agreements. 
4    (j-5) A commercial wind energy facility or a commercial 
5solar energy facility shall file a farmland drainage plan with 
6the county and impacted drainage districts outlining how 
7surface and subsurface drainage of farmland will be restored 
8during and following construction or deconstruction of the 
9facility. The plan is to be created independently by the 
10facility developer and shall include the location of any 
11potentially impacted drainage district facilities to the 
12extent this information is publicly available from the county 
13or the drainage district, plans to repair any subsurface 
14drainage affected during construction or deconstruction using 
15procedures outlined in the agricultural impact mitigation 
16agreement entered into by the commercial wind energy facility 
17owner or commercial solar energy facility owner, and 
18procedures for the repair and restoration of surface drainage 
19affected during construction or deconstruction. All surface 
20and subsurface damage shall be repaired as soon as reasonably 
21practicable. 
22    (k) A county may not condition approval of a commercial 
23wind energy facility or commercial solar energy facility on a 
24property value guarantee and may not require a facility owner 
25to pay into a neighboring property devaluation escrow account. 
26    (l) A county may require certain vegetative screening 
 
 
10400SB0025ham004- 477 -LRB104 16098 AAS 29398 a

1between a surrounding a commercial wind energy facility or    
2commercial solar energy facility and nonparticipating 
3residences. A county but may not require earthen berms or 
4similar structures. Vegetative screening requirements shall be 
5commercially reasonable and limited in height at full maturity 
6to avoid reduction of the productive energy output of the 
7commercial solar energy facility. A county may not require 
8vegetative screening to exceed 5 feet in height when first 
9installed or prior to commercial operation date. The screening 
10requirements shall take into account the size and location of 
11the facility, visibility from nonparticipating residences, 
12compatibility of native plant species, cost and feasibility of 
13installation and maintenance, and industry standards and best 
14practices for commercial solar energy facilities.    
15    (m) A county may set blade tip height limitations for wind 
16towers in commercial wind energy facilities but may not set a 
17blade tip height limitation that is more restrictive than the 
18height allowed under a Determination of No Hazard to Air 
19Navigation by the Federal Aviation Administration under 14 CFR 
20Part 77.
21    (n) A county may require that a commercial wind energy 
22facility owner or commercial solar energy facility owner 
23provide:
24        (1) the results and recommendations from consultation 
25    with the Illinois Department of Natural Resources that are 
26    obtained through the Ecological Compliance Assessment Tool 
 
 
10400SB0025ham004- 478 -LRB104 16098 AAS 29398 a

1    (EcoCAT) or a comparable successor tool; and
2        (2) (blank). the results of the United States Fish and 
3    Wildlife Service's Information for Planning and Consulting 
4    environmental review or a comparable successor tool that 
5    is consistent with (i) the "U.S. Fish and Wildlife 
6    Service's Land-Based Wind Energy Guidelines" and (ii) any 
7    applicable United States Fish and Wildlife Service solar 
8    wildlife guidelines that have been subject to public 
9    review.    
10    (o) A county may require a commercial wind energy facility 
11or commercial solar energy facility to adhere to the 
12recommendations provided by the Illinois Department of Natural 
13Resources in an EcoCAT natural resource review report under 17 
14Ill. Adm. Code Part 1075. 
15    (p) A county may require a facility owner to:
16        (1) demonstrate avoidance of protected lands as 
17    identified by the Illinois Department of Natural Resources 
18    and the Illinois Nature Preserve Commission; or
19        (2) consider the recommendations of the Illinois 
20    Department of Natural Resources for setbacks from 
21    protected lands, including areas identified by the 
22    Illinois Nature Preserve Commission.
23    (q) A county may require that a facility owner provide 
24evidence of consultation with the Illinois State Historic 
25Preservation Office to assess potential impacts on 
26State-registered historic sites under the Illinois State 
 
 
10400SB0025ham004- 479 -LRB104 16098 AAS 29398 a

1Agency Historic Resources Preservation Act. 
2    (r) To maximize community benefits, including, but not 
3limited to, reduced stormwater runoff, flooding, and erosion 
4at the ground mounted solar energy system, improved soil 
5health, and increased foraging habitat for game birds, 
6songbirds, and pollinators, a county may (1) require a 
7commercial solar energy facility owner to plant, establish, 
8and maintain for the life of the facility vegetative ground 
9cover, consistent with the goals of the Pollinator-Friendly 
10Solar Site Act and (2) require the submittal of a vegetation 
11management plan that is in compliance with the agricultural 
12impact mitigation agreement in the application to construct 
13and operate a commercial solar energy facility in the county 
14if the vegetative ground cover and vegetation management plan 
15comply with the requirements of the underlying agreement with 
16the landowner or landowners where the facility will be 
17constructed. 
18    No later than 90 days after January 27, 2023 (the 
19effective date of Public Act 102-1123), the Illinois 
20Department of Natural Resources shall develop guidelines for 
21vegetation management plans that may be required under this 
22subsection for commercial solar energy facilities. The 
23guidelines must include guidance for short-term and long-term 
24property management practices that provide and maintain native 
25and non-invasive naturalized perennial vegetation to protect 
26the health and well-being of pollinators. 
 
 
10400SB0025ham004- 480 -LRB104 16098 AAS 29398 a

1    (s) If a facility owner enters into a road use agreement 
2with the Illinois Department of Transportation, a road 
3district, or other unit of local government relating to a 
4commercial wind energy facility or a commercial solar energy 
5facility, the road use agreement shall require the facility 
6owner to be responsible for (i) the reasonable cost of 
7improving roads used by the facility owner to construct the 
8commercial wind energy facility or the commercial solar energy 
9facility and (ii) the reasonable cost of repairing roads used 
10by the facility owner during construction of the commercial 
11wind energy facility or the commercial solar energy facility 
12so that those roads are in a condition that is safe for the 
13driving public after the completion of the facility's 
14construction. Roadways improved in preparation for and during 
15the construction of the commercial wind energy facility or 
16commercial solar energy facility shall be repaired and 
17restored to the improved condition at the reasonable cost of 
18the developer if the roadways have degraded or were damaged as 
19a result of construction-related activities.
20    The road use agreement shall not require the facility 
21owner to pay costs, fees, or charges for road work that is not 
22specifically and uniquely attributable to the construction of 
23the commercial wind energy facility or the commercial solar 
24energy facility. No road district or other unit of local 
25government may request or require permit fees, fines, or other 
26payment obligations as a requirement for a road use agreement 
 
 
10400SB0025ham004- 481 -LRB104 16098 AAS 29398 a

1with a facility owner unless the amount of the reasonable 
2permit fee or payment is equivalent to the amount of actual 
3expenses incurred by the road district or other unit of local 
4government for negotiating, executing, constructing, or 
5implementing the road use agreement. The road use agreement 
6shall not require any road work to be performed by or paid for 
7by the facility owner that is not specifically and uniquely 
8attributable to the road improvements required for the 
9construction of the commercial wind energy facility or the 
10commercial solar energy facility or the restoration of the 
11roads used by the facility owner during construction-related 
12activities. Road-related fees, permit fees, or other charges 
13imposed by the Illinois Department of Transportation, a road 
14district, or other unit of local government under a road use 
15agreement with the facility owner shall be reasonably related 
16to the cost of administration of the road use agreement.    
17    (s-5) The facility owner shall also compensate landowners 
18for crop losses or other agricultural damages resulting from 
19damage to the drainage system caused by the construction of 
20the commercial wind energy facility or the commercial solar 
21energy facility. The commercial wind energy facility owner or 
22commercial solar energy facility owner shall repair or pay for 
23the repair of all damage to the subsurface drainage system 
24caused by the construction of the commercial wind energy 
25facility or the commercial solar energy facility in accordance 
26with the agriculture impact mitigation agreement requirements 
 
 
10400SB0025ham004- 482 -LRB104 16098 AAS 29398 a

1for repair of drainage. The commercial wind energy facility 
2owner or commercial solar energy facility owner shall repair 
3or pay for the repair and restoration of surface drainage 
4caused by the construction or deconstruction of the commercial 
5wind energy facility or the commercial solar energy facility 
6as soon as reasonably practicable. 
7    (t) Notwithstanding any other provision of law, a facility 
8owner with siting approval from a county to construct a 
9commercial wind energy facility or a commercial solar energy 
10facility is authorized to cross or impact a drainage system, 
11including, but not limited to, drainage tiles, open drainage 
12ditches, culverts, and water gathering vaults, owned or under 
13the control of a drainage district under the Illinois Drainage 
14Code without obtaining prior agreement or approval from the 
15drainage district in accordance with the farmland drainage 
16plan required by subsection (j-5). 
17    (u) The amendments to this Section adopted in Public Act 
18102-1123 do not apply to: (1) an application for siting 
19approval or for a special use permit for a commercial wind 
20energy facility or commercial solar energy facility if the 
21application was submitted to a unit of local government before 
22January 27, 2023 (the effective date of Public Act 102-1123); 
23(2) a commercial wind energy facility or a commercial solar 
24energy facility if the facility owner has submitted an 
25agricultural impact mitigation agreement to the Department of 
26Agriculture before January 27, 2023 (the effective date of 
 
 
10400SB0025ham004- 483 -LRB104 16098 AAS 29398 a

1Public Act 102-1123); or (3) a commercial wind energy or 
2commercial solar energy development on property that is 
3located within an enterprise zone certified under the Illinois 
4Enterprise Zone Act, that was classified as industrial by the 
5appropriate zoning authority on or before January 27, 2023, 
6and that is located within 4 miles of the intersection of 
7Interstate 88 and Interstate 39; or (4) a commercial wind 
8energy or commercial solar energy development on property in 
9Madison County that is located within the area that has as its 
10northern boundary the portion of Drexelius Road that is 
11between the intersection of Drexelius Road and Wolf Road and 
12the intersection of Drexelius Road and Fosterburg Road, that 
13has as its eastern boundary the portion of Fosterburg Road 
14that is between the intersection of Fosterburg Road and 
15Drexelius Road and the intersection of Fosterburg Road and 
16Wolf Road, and that has as its southern and western boundaries 
17the portion of Wolf Road that is between the intersection of 
18Fosterburg Road and Wolf Road and the intersection of 
19Drexelius Road and Wolf Road.
20(Source: P.A. 102-1123, eff. 1-27-23; 103-81, eff. 6-9-23; 
21103-580, eff. 12-8-23; revised 7-29-24.)
 
22    (55 ILCS 5/5-12024 new)
23    Sec. 5-12024. Energy storage systems.
24    (a) As used in this Section:
25    "Energy storage system" means a facility with an aggregate 
 
 
10400SB0025ham004- 484 -LRB104 16098 AAS 29398 a

1energy capacity that is greater than 1,000 kilowatts and that 
2is capable of absorbing energy and storing it for use at a 
3later time, including, but not limited to, electrochemical and 
4electromechanical technologies. "Energy storage system" does 
5not include technologies that require combustion. "Energy 
6storage system" also does not include energy storage systems 
7associated with commercial solar energy facilities or 
8commercial wind energy facilities as defined in Section 
95-12020.
10    "Excused service interruption" means any period during 
11which an energy storage system does not store or discharge 
12electricity and that is planned or reasonably foreseeable for 
13standard commercial operation, including any unavailability 
14caused by a buyer; storage capacity tests; system emergencies; 
15curtailments, including curtailment orders; transmission 
16system outages; compliance with any operating restriction; 
17serial defects; and planned outages.
18    "Facility owner" means (i) a person with a direct 
19ownership interest in an energy storage system, regardless of 
20whether the person is involved in acquiring the necessary 
21rights, permits, and approvals or otherwise planning for the 
22construction and operation of the facility and (ii) a person 
23who, at the time the facility is being developed, is acting as 
24a developer of the facility by acquiring the necessary rights, 
25permits, and approvals or by planning for the construction and 
26operation of the facility, regardless of whether the person 
 
 
10400SB0025ham004- 485 -LRB104 16098 AAS 29398 a

1will own or operate the facility.
2    "Force majeure" means any event or circumstance that 
3delays or prevents an energy storage system from timely 
4performing all or a portion of its commercial operations if 
5the act or event, despite the exercise of commercially 
6reasonable efforts, cannot be avoided by and is beyond the 
7reasonable control, whether direct or indirect, of, and 
8without the fault or negligence of, a facility owner or 
9operator or any of its assignees. "Force majeure" includes, 
10but is not limited to:
11        (1) fire, flood, tornado, or other natural disasters 
12    or acts of God;
13        (2) war, civil strife, terrorist attack, or other 
14    similar acts of violence;
15        (3) unavailability of materials, equipment, services, 
16    or labor, including unavailability due to global supply 
17    chain shortages;
18        (4) utility or energy shortages or acts or omissions 
19    of public utility providers;
20        (5) any delay resulting from a pandemic, epidemic, or 
21    other public health emergency or related restrictions; and
22        (6) litigation or a regulatory proceeding regarding a 
23    facility.
24    "NFPA" means the National Fire Protection Association.
25    "Nonparticipating property" means real property that is 
26not a participating property.
 
 
10400SB0025ham004- 486 -LRB104 16098 AAS 29398 a

1    "Nonparticipating residence" means a residence that is 
2located on nonparticipating property and that exists and is 
3occupied on the date that the application for a permit to 
4develop an energy storage system is filed with the county.
5    "Occupied community building" means a school, place of 
6worship, day care facility, public library, or community 
7center that is occupied on the date that the application for a 
8permit to develop an energy storage system is filed with the 
9county in which the building is located.
10    "Participating property" means real property that is the 
11subject of a written agreement between a facility owner and 
12the owner of the real property and that provides the facility 
13owner an easement, option, lease, or license to use the real 
14property for the purpose of constructing an energy storage 
15system or supporting facilities.
16    "Protected lands" means real property that is: (i) subject 
17to a permanent conservation right consistent with the Real 
18Property Conservation Rights Act; or (ii) registered or 
19designated as a nature preserve, buffer, or land and water 
20reserve under the Illinois Natural Areas Preservation Act.
21    "Supporting facilities" means the transmission lines, 
22substations, switchyard, access roads, meteorological towers, 
23storage containers, and equipment associated with the 
24generation, storage, and dispatch of electricity by an energy 
25storage system.
26    (b) Notwithstanding any other provision of law, if a 
 
 
10400SB0025ham004- 487 -LRB104 16098 AAS 29398 a

1county has formed a zoning commission and adopted formal 
2zoning under Section 5-12007, then a county may establish 
3standards for energy storage systems in areas of the county 
4that are not within the zoning jurisdiction of a municipality. 
5The standards may include all of the requirements specified in 
6this Section but may not include requirements for energy 
7storage systems that are more restrictive than specified in 
8this Section or requirements that are not specified in this 
9Section.
10    (c) A county may require the energy storage facility to 
11comply with the version of NFPA 855 "Standard for the 
12Installation of Stationary Energy Storage Systems" in effect 
13on the effective date of this amendatory Act or any successor 
14standard issued by the NFPA in effect on the date of siting or 
15special use permit approval. A county may not include 
16requirements for energy storage systems that are more 
17restrictive than NFPA 855 "Standard for the Installation of 
18Stationary Energy Storage Systems" unless required by this 
19Section.
20    (d) If a county has elected to establish standards under 
21subsection (b), then the zoning board of appeals for the 
22county shall hold at least one public hearing before the 
23county grants (i) siting approval or a special use permit for 
24an energy storage system or (ii) modification of an approved 
25siting or special use permit. The public hearing shall be 
26conducted in accordance with the Open Meetings Act and shall 
 
 
10400SB0025ham004- 488 -LRB104 16098 AAS 29398 a

1conclude not more than 60 days after the filing of the 
2application for the facility. The county shall allow 
3interested parties to a special use permit an opportunity to 
4present evidence and to cross-examine witnesses at the 
5hearing, but the county may impose reasonable restrictions on 
6the public hearing, including reasonable time limitations on 
7the presentation of evidence and the cross-examination of 
8witnesses. The county shall also allow public comment at the 
9public hearing in accordance with the Open Meetings Act. The 
10county shall make its siting and permitting decisions not more 
11than 30 days after the conclusion of the public hearing. 
12Notice of the hearing shall be published in a newspaper of 
13general circulation in the county.
14    (e) A county with an existing zoning ordinance in conflict 
15with this Section shall amend that zoning ordinance to comply 
16with this Section within 120 days after the effective date of 
17this amendatory Act of the 104th General Assembly.
18    (f) A county shall require an energy storage system to be 
19sited as follows, with setback distances measured from the 
20nearest edge of the nearest battery or other electrochemical 
21or electromechanical enclosure:
 
22Setback Description           Setback Distance
 
23Occupied Community            150 feet from the nearest 
24Buildings and                 point of the outside wall of
 
 
10400SB0025ham004- 489 -LRB104 16098 AAS 29398 a

1Nonparticipating Residences   the occupied community building
2                              or nonparticipating residence
 
3Boundary Lines of             50 feet to the nearest point
4Occupied Community            on the property line of
5Buildings and                 the occupied community building
6Nonparticipating Residences   or nonparticipating property
 
7Public Road Rights-of-Way     50 feet from the nearest edge
8                              of the right-of-way
9        (2) A county shall also require an energy storage 
10    system to be sited so that the facility's perimeter is 
11    enclosed by fencing having a height of at least 7 feet and 
12    no more than 25 feet.
13    This Section does not exempt or excuse compliance with 
14electric facility clearances approved or required by the 
15National Electrical Code, the National Electrical Safety Code, 
16the Illinois Commerce Commission, the Federal Energy 
17Regulatory Commission, and their designees or successors.
18    (g) A county may not set a sound limitation for energy 
19storage systems that is more restrictive than the sound 
20limitations established by the Illinois Pollution Control 
21Board under 35 Ill. Adm. Code Parts 900, 901, and 910. After 
22commercial operation, a county may require the facility owner 
23to provide, not more than once, octave band sound pressure 
24level measurements from a reasonable number of sampled 
 
 
10400SB0025ham004- 490 -LRB104 16098 AAS 29398 a

1locations at the perimeter of the energy storage system to 
2demonstrate compliance with this Section.
3    (h) The provisions set forth in subsection (f) may be 
4waived subject to the written consent of the owner of each 
5affected nonparticipating property or nonparticipating 
6residence.
7    (i) A county may not place any restriction on the 
8installation or use of an energy storage system unless it has 
9formed a zoning commission and adopted formal zoning under 
10Section 5-12007 and adopts an ordinance that complies with 
11this Section. A county may not establish siting standards for 
12supporting facilities that preclude development of an energy 
13storage system.
14    (j) A request for siting approval or a special use permit 
15for an energy storage system, or modification of an approved 
16siting approval or special use permit, shall be approved if 
17the request complies with the standards and conditions imposed 
18in this Code, the zoning ordinance adopted consistent with 
19this Section, and other State and federal statutes and 
20regulations. The siting approval or special use permit 
21approved by the county shall grant the facility owner a period 
22of at least 3 years after county approval to obtain a building 
23permit or commence construction of the energy storage system, 
24before the siting approval or special use permit may become 
25subject to revocation by the county. Facility owners may be 
26granted an extension on obtaining building permits or 
 
 
10400SB0025ham004- 491 -LRB104 16098 AAS 29398 a

1commencing constructing upon a showing of good cause. A 
2facility owner's request for an extension may not be 
3unreasonably withheld, conditioned, or denied.
4    (k) A county may not adopt zoning regulations that 
5disallow, permanently or temporarily, an energy storage system 
6from being developed or operated in any district zones to 
7allow agricultural or industrial uses.
8    (l) A facility owner shall file a farmland drainage plan 
9with the county and impacted drainage districts that outlines 
10how surface and subsurface drainage of farmland will be 
11restored during and following the construction or 
12deconstruction of the energy storage system. The plan shall be 
13created independently by the facility owner and shall include 
14the location of any potentially impacted drainage district 
15facilities to the extent the information is publicly available 
16from the county or the drainage district and plans to repair 
17any subsurface drainage affected during construction or 
18deconstruction using procedures outlined in the 
19decommissioning plan. All surface and subsurface damage shall 
20be repaired as soon as reasonably practicable.
21    (m) A facility owner shall compensate landowners for crop 
22losses or other agricultural damages resulting from damage to 
23a drainage system caused by the construction of an energy 
24storage system. The facility owner shall repair or pay for the 
25repair of all damage to the subsurface drainage system caused 
26by the construction of the energy storage system. The facility 
 
 
10400SB0025ham004- 492 -LRB104 16098 AAS 29398 a

1owner shall repair or pay for the repair and restoration of 
2surface drainage caused by the construction or deconstruction 
3of the energy storage facility as soon as reasonably 
4practicable.    
5    (n) County siting approval or special use permit 
6application fees for an energy storage system shall not exceed 
7the lesser of (i) $5,000 per each megawatt of nameplate 
8capacity of the energy storage system or (ii) $50,000.
9    (o) The county may require a facility owner to provide a 
10decommissioning plan to the county. The decommissioning plan 
11may include all requirements for decommissioning plans in NFPA 
12855 and may also require the facility owner to:
13        (1) state how the energy storage system will be 
14    decommissioned, including removal to a depth of 3 feet of 
15    all structures that have no ongoing purpose and all debris 
16    and restoration of the soil and any vegetation to a 
17    condition as close as reasonably practicable to the soil's 
18    and vegetation's preconstruction condition within 18 
19    months of the end of project life or facility abandonment;
20        (2) include provisions related to commercially 
21    reasonable efforts to reuse or recycle of equipment and 
22    components associated with the commercial offsite energy 
23    storage system;
24        (3) include financial assurance in the form of a 
25    reclamation or surety bond or other commercially available 
26    financial assurance that is acceptable to the county, with 
 
 
10400SB0025ham004- 493 -LRB104 16098 AAS 29398 a

1    the county or participating property owner as beneficiary. 
2    The amount of the financial assurance shall not be more 
3    than the estimated cost of decommissioning the energy 
4    facility, after deducting salvage value, as calculated by 
5    a professional engineer licensed to practice engineering 
6    in this State with expertise in preparing decommissioning 
7    estimates, retained by the applicant. The financial 
8    assurance shall be provided to the county incrementally as 
9    follows:
10            (A) 25% before the start of full commercial 
11        operation;
12            (B) 50% before the start of the 5th year of 
13        commercial operation; and
14            (C) 100% by the start of the tenth year of 
15        commercial operation;
16        (4) update the amount of the financial assurance not 
17    more than every 5 years for the duration of commercial 
18    operations. The amount shall be calculated by a 
19    professional engineer licensed to practice engineering in 
20    this State with expertise in decommissioning, hired by the 
21    facility owner; and
22        (5) decommission the energy storage system, in 
23    accordance with an approved decommissioning plan, within 
24    18 months after abandonment. An energy storage system that 
25    has not stored electrical energy for 12 consecutive months 
26    or that fails, for a period of 6 consecutive months, to pay 
 
 
10400SB0025ham004- 494 -LRB104 16098 AAS 29398 a

1    a property owner who is party to a written agreement, 
2    including, but not limited to, an easement, option, lease, 
3    or license under the terms of which an energy storage 
4    system is constructed on the property, amounts owed in 
5    accordance with the written agreement shall be considered 
6    abandoned, except when the inability to store energy is 
7    the result of an event of force majeure or excused service 
8    interruption.
9    (p) A county may not condition approval of an energy 
10storage system on a property value guarantee and may not 
11require a facility owner to pay into a neighboring property 
12devaluation escrow account.
13    (q) A county may require that a facility owner provide the 
14results and recommendations from consultation with the 
15Department of Natural Resources that are obtained through the 
16Ecological Compliance Assessment Tool (EcoCAT) or a comparable 
17successor tool.
18    (r) A county may require an energy storage system to 
19adhere to the recommendations provided by the Department of 
20Natural Resources in an Agency Action Report under 17 Ill. 
21Adm. Code 1075.
22    (s) A county may require a facility owner to:
23        (1) demonstrate avoidance of protected lands as 
24    identified by the Department of Natural Resources and the 
25    Illinois Nature Preserves Commission; or
26        (2) consider the recommendations of the Department of 
 
 
10400SB0025ham004- 495 -LRB104 16098 AAS 29398 a

1    Natural Resources for setbacks from protected lands, 
2    including areas identified by the Illinois Nature 
3    Preserves Commission.
4    (t) A county may require that a facility owner provide 
5evidence of consultation with the Illinois Historic 
6Preservation Division to assess potential impacts on 
7State-registered historic sites under the Illinois State 
8Agency Historic Resources Preservation Act.
9    (u) A county may require that an application for siting 
10approval or special use permit include the following 
11information on a site plan:
12        (1) a description of the property lines and physical 
13    features, including roads, for the facility site;
14        (2) a description of the proposed changes to the 
15    landscape of the facility site, including vegetation 
16    clearing and planting, exterior lighting, and screening or 
17    structures; and
18        (3) a description of the zoning district designation 
19    for the parcel of land comprising the facility site.
20    (v) A county may not prohibit an energy storage system 
21from undertaking periodic augmentation to maintain the 
22approximate original capacity of the energy storage system. A 
23county may not require renewed or additional siting approval 
24or special use permit approval of periodic augmentation to 
25maintain the approximate original capacity of the energy 
26storage system.
 
 
10400SB0025ham004- 496 -LRB104 16098 AAS 29398 a

1    (w) A county that issues a building permit for energy 
2storage systems shall review and process building permit 
3applications within 60 days after receipt of the building 
4permit application. If a county does not grant or deny the 
5building permit application within 60 days, the building 
6permit shall be deemed granted. If a county denies a building 
7permit application, it shall specify the reason for the denial 
8in writing as part of its denial.
9    (x) A county may require a single building permit and a 
10reasonable permit fee for the facility which includes all 
11supporting facilities. A county building permit fee for an 
12energy storage system that does not exceed the lesser of (i) 
13$5,000 per each megawatt of nameplate capacity of the energy 
14storage system or (ii) $50,000 shall be considered 
15presumptively reasonable. A county may require that the 
16application for building permit contain:
17        (1) an electrical diagram detailing the battery energy 
18    storage system layout, associated components, and 
19    electrical interconnection methods, with all National 
20    Electrical Code compliant disconnects and overcurrent 
21    devices; and
22        (2) an equipment specification sheet.
23    (y) A county may require the facility owner to submit to 
24the county prior to the facility's commercial operation a 
25commissioning report meeting the requirements of NFPA 855 
26Sections 4.2.4, 6.1.3, and 6.1.5.5, as published in 2023, or 
 
 
10400SB0025ham004- 497 -LRB104 16098 AAS 29398 a

1the applicable Sections in the most recent version of NFPA 
2855.
3    (z) A county may require the facility owner to submit to 
4the county prior to the facility's commercial operation a 
5hazard mitigation analysis meeting the requirements of NFPA 
6855 Section 4.4 or the applicable Sections in the most recent 
7version of NFPA 855.
8    (aa) A county may require the facility owner to submit to 
9the county an emergency operations plan meeting the 
10requirements of NFPA 855 Section 4.3.2.1.4, published in 2023, 
11or applicable Sections in the most recent version of NFPA 855, 
12prior to commercial operation.
13    (bb) A county may require a warning that complies with 
14requirements in NFPA 855 Section 4.7.4, published in 2023, or 
15applicable sections in the most recent version of NFPA 855.
16    (cc) A county may require the energy storage system to 
17adhere to the principles for responsible outdoor lighting 
18provided by the International Dark-Sky Association and shall 
19limit outdoor lighting to that which is minimally required for 
20safety and operational purposes. Any outdoor lighting shall be 
21reasonably shielded and downcast from all residences and 
22adjacent properties.
23    (dd) This Section does not exempt compliance with fire and 
24safety standards and guidance established for the installation 
25of lithium-ion battery energy storage systems set by the NFPA.
26    (ee) Prior to commencement of commercial operation, the 
 
 
10400SB0025ham004- 498 -LRB104 16098 AAS 29398 a

1facility owner shall offer to provide training for local fire 
2departments and emergency responders in accordance with the 
3facility emergency operations plan. A copy of the emergency 
4operations plan shall be given to the facility owner, the 
5local fire department, and emergency responders. All batteries 
6integrated within an energy storage system shall be listed 
7under the UL 1973 Standard. All batteries integrated within an 
8energy storage system shall be listed in accordance with UL 
99540 Standard, either from the manufacturer or by a field 
10evaluation.
11    (ff) If a facility owner enters into a road use agreement 
12with the Department of Transportation, a road district, or 
13other unit of local government relating to an energy storage 
14system, then the road use agreement shall require the facility 
15owner to be responsible for (i) the reasonable cost of 
16improving, if necessary, roads used by the facility owner to 
17construct the energy storage system and (ii) the reasonable 
18cost of repairing roads used by the facility owner during 
19construction of the energy storage system so that those roads 
20are in a condition that is safe for the driving public after 
21the completion of the facility's construction. A roadway 
22improved in preparation for and during the construction of the 
23energy storage system shall be repaired and restored to the 
24improved condition at the reasonable cost of the developer if 
25the roadways have degraded or were damaged as a result of 
26construction-related activities.
 
 
10400SB0025ham004- 499 -LRB104 16098 AAS 29398 a

1    The road use agreement shall not require the facility 
2owner to pay costs, fees, or charges for road work that is not 
3specifically and uniquely attributable to the construction of 
4the energy storage system. No road district or other unit of 
5local government may request or require a fine, permit fee, or 
6other payment obligation as a requirement for a road use 
7agreement with a facility owner unless the amount of the fine, 
8permit fee, or other payment obligation is equivalent to the 
9amount of actual expenses incurred by the road district or 
10other unit of local government for negotiating, executing, 
11constructing, or implementing the road use agreement. The road 
12use agreement shall not require the facility owner to perform 
13or pay for any road work that is unrelated to the road 
14improvements required for the construction of the commercial 
15wind energy facility or the commercial solar energy facility 
16or the restoration of the roads used by the facility owner 
17during construction-related activities.
18    (gg) The provisions of this amendatory Act of the 104th 
19General Assembly do not apply to an application for siting 
20approval or special use permit for an energy storage system if 
21the application was submitted to a county before the effective 
22date of this amendatory Act of the 104th General Assembly.
 
23    (55 ILCS 5/Art. 5 Div. 5-46 heading new)
24
Division 5-46.  Solar Bill of Rights

 
 
 
10400SB0025ham004- 500 -LRB104 16098 AAS 29398 a

1    (55 ILCS 5/5-46005 new)
2    Sec. 5-46005. Definitions. As used in this Division:
3    "Low-voltage solar-powered device" means a piece of 
4equipment designed for a particular purpose, including, but 
5not limited to, doorbells, security systems, and illumination 
6equipment, powered by a solar collector operating at less than 
750 volts, and located:
8        (1) entirely within the lot or parcel owned by the 
9    property owner; or
10        (2) within a common area without being permanently 
11    attached to common property.
12    "Solar collector" means:
13        (1) an assembly, structure, or design, including 
14    passive elements, used for gathering, concentrating, or 
15    absorbing direct and indirect solar energy and specially 
16    designed for holding a substantial amount of useful 
17    thermal energy and to transfer that energy to a gas, 
18    solid, or liquid or to use that energy directly;
19        (2) a mechanism that absorbs solar energy and converts 
20    it into electricity;
21        (3) a mechanism or process used for gathering solar 
22    energy through wind or thermal gradients; or
23        (4) a component used to transfer thermal energy to a 
24    gas, solid, or liquid, or to convert it into electricity.
25    "Solar energy" means radiant energy received from the sun 
26at wavelengths suitable for heat transfer, photosynthetic use, 
 
 
10400SB0025ham004- 501 -LRB104 16098 AAS 29398 a

1or photovoltaic use.
2    "Solar energy system" means:
3        (1) a complete assembly, structure, or design of a 
4    solar collector or a solar storage mechanism that uses 
5    solar energy for generating electricity or for heating or 
6    cooling gases, solids, liquids, or other materials; and
7        (2) the design, materials, or elements of a system and 
8    its maintenance, operation, and labor components, and the 
9    necessary components, if any, of supplemental conventional 
10    energy systems designed or constructed to interface with a 
11    solar energy system.
12    "Solar storage mechanism" means equipment or elements, 
13such as piping and transfer mechanisms, containers, heat 
14exchangers, batteries, or controls thereof and gases, solids, 
15liquids, or combinations thereof, that are utilized for 
16storing solar energy, gathered by a solar collector, for 
17subsequent use.
 
18    (55 ILCS 5/5-46010 new)
19    Sec. 5-46010. Prohibitions. Notwithstanding any provision 
20of this Code or other provision of law, the adoption of any 
21ordinance or resolution or the exercise of any power by a 
22county that prohibits or has the effect of prohibiting the 
23installation of a solar energy system or low-voltage 
24solar-powered devices is expressly prohibited.
 
 
 
10400SB0025ham004- 502 -LRB104 16098 AAS 29398 a

1    (55 ILCS 5/5-46020 new)
2    Sec. 5-46020. Costs; attorney's fees. In any litigation 
3arising under this Division or involving the application of 
4this Division, the prevailing party shall be entitled to costs 
5and reasonable attorney's fees.
 
6    (55 ILCS 5/5-46025 new)
7    Sec. 5-46025. Applicability.
8    (a) As used in this Section, "shared roof" means any roof 
9that (i) serves more than one unit, including, but not limited 
10to, a contiguous roof serving adjacent units, or (ii) is part 
11of the common elements or common area of a unit.
12    (b) This Division shall not apply to any building that:
13        (1) is greater than 60 feet in height; or
14        (2) has a shared roof.
15    (c) Notwithstanding subsection (b) of this Section, this 
16Division shall apply to any building with a shared roof:
17        (1) where the solar energy system is located entirely 
18    within that portion of the shared roof that is owned and 
19    maintained by the property owner;
20        (2) where all property owners sharing the shared roof 
21    are in agreement to install a solar energy system; or
22        (3) to the extent this Division applies to low-voltage 
23    solar-powered devices.    
 
24    Section 90-30. The Illinois Municipal Code is amended by 
 
 
10400SB0025ham004- 503 -LRB104 16098 AAS 29398 a

1adding Division 15.5 as follows:
 
2    (65 ILCS 5/Art. 11 Div. 15.5 heading new)
3
Division 15.5.  Solar Bill of Rights

 
4    (65 ILCS 5/11-15.5-5 new)
5    Sec. 11-15.5-5. Definitions. As used in this Division:
6    "Low-voltage solar-powered device" means a piece of 
7equipment designed for a particular purpose, including, but 
8not limited to, doorbells, security systems, and illumination 
9equipment, powered by a solar collector operating at less than 
1050 volts, and located:
11        (1) entirely within the lot or parcel owned by the 
12    property owner; or
13        (2) within a common area without being permanently 
14    attached to common property.
15    "Solar collector" means:
16        (1) an assembly, structure, or design, including 
17    passive elements, used for gathering, concentrating, or 
18    absorbing direct and indirect solar energy and specially 
19    designed for holding a substantial amount of useful 
20    thermal energy and to transfer that energy to a gas, 
21    solid, or liquid or to use that energy directly;
22        (2) a mechanism that absorbs solar energy and converts 
23    it into electricity;
24        (3) a mechanism or process used for gathering solar 
 
 
10400SB0025ham004- 504 -LRB104 16098 AAS 29398 a

1    energy through wind or thermal gradients; or
2        (4) a component used to transfer thermal energy to a 
3    gas, solid, or liquid, or to convert it into electricity.
4    "Solar energy" means radiant energy received from the sun 
5at wavelengths suitable for heat transfer, photosynthetic use, 
6or photovoltaic use.
7    "Solar energy system" means:
8        (1) a complete assembly, structure, or design of a 
9    solar collector or a solar storage mechanism that uses 
10    solar energy for generating electricity or for heating or 
11    cooling gases, solids, liquids, or other materials; and
12        (2) the design, materials, or elements of a system and 
13    its maintenance, operation, and labor components, and the 
14    necessary components, if any, of supplemental conventional 
15    energy systems designed or constructed to interface with a 
16    solar energy system.
17    "Solar storage mechanism" means equipment or elements, 
18such as piping and transfer mechanisms, containers, heat 
19exchangers, batteries, or controls thereof and gases, solids, 
20liquids, or combinations thereof, that are utilized for 
21storing solar energy, gathered by a solar collector, for 
22subsequent use.
 
23    (65 ILCS 5/11-15.5-10 new)
24    Sec. 11-15.5-10. Prohibitions. Notwithstanding any 
25provision of this Code or other provision of law, the adoption 
 
 
10400SB0025ham004- 505 -LRB104 16098 AAS 29398 a

1of any ordinance or resolution or the exercise of any power, by 
2municipality that prohibits or has the effect of prohibiting 
3the installation of a solar energy system or low-voltage 
4solar-powered devices is expressly prohibited. Municipalities 
5that own local electric distribution systems may adopt and 
6implement reasonable policies, consistent with Section 17-900 
7of the Public Utilities Act, regarding the interconnection and 
8use of solar energy systems.
 
9    (65 ILCS 5/11-15.5-20 new)
10    Sec. 11-15.5-20. Costs; attorney's fees. In any litigation 
11arising under this Division or involving the application of 
12this Division, the prevailing party shall be entitled to costs 
13and reasonable attorney's fees.
 
14    (65 ILCS 5/11-15.5-25 new)
15    Sec. 11-15.5-25. Applicability.
16    (a) As used in this Section, "shared roof" means any roof 
17that (i) serves more than one unit, including, but not limited 
18to, a contiguous roof serving adjacent units, or (ii) is part 
19of the common elements or common area of a unit.
20    (b) This Division shall not apply to any building that:
21        (1) is greater than 60 feet in height; or
22        (2) has a shared roof.
23    (c) Notwithstanding subsection (b) of this Section, this 
24Division shall apply to any building with a shared roof:
 
 
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1        (1) where the solar energy system is located entirely 
2    within that portion of the shared roof owned and 
3    maintained by the property owner;
4        (2) where all property owners sharing the shared roof 
5    are in agreement to install a solar energy system; or
6        (3) to the extent this Division applies to low-voltage 
7    solar-powered devices.
 
8    Section 90-35. The Public Utilities Act is amended by 
9changing Sections 7-102, 8-103B, 8-104, 8-512, 9-229, 
1016-107.5, 16-107.6, 16-108, 16-108.19, 16-108.30, 16-111.5, 
1116-111.7, 16-115A, 16-119A, and 17-900 and by adding Sections 
128-101.1, 8-513, 16-105.17, 16-107.8, 16-107.9, 16-126.2, 
1316-145, 16-201, 16-202, 20-140, 20-145, and Article 23 as 
14follows:
 
15    (220 ILCS 5/7-102)  (from Ch. 111 2/3, par. 7-102)
16    Sec. 7-102. Transactions requiring Commission approval. 
17    (A) Unless the consent and approval of the Commission is 
18first obtained or unless such approval is waived by the 
19Commission or is exempted in accordance with the provisions of 
20this Section or of any other Section of this Act:    
21        (a) No 2 or more public utilities may enter into 
22    contracts with each other that will enable such public 
23    utilities to operate their lines or plants in connection 
24    with each other.    
 
 
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1        (b) No public utility may purchase, lease, or in any 
2    other manner acquire control, direct or indirect, over the 
3    franchises, licenses, permits, plants, equipment, business 
4    or other property of any other public utility.    
5        (c) No public utility may assign, transfer, lease, 
6    mortgage, sell (by option or otherwise), or otherwise 
7    dispose of or encumber the whole or any part of its 
8    franchises, licenses, permits, plant, equipment, business, 
9    or other property, but the consent and approval of the 
10    Commission shall not be required for the sale, lease, 
11    assignment or transfer (1) by any public utility of any 
12    tangible personal property which is not necessary or 
13    useful in the performance of its duties to the public, or    
14    (2) by any electric utility, as defined by Section 16-105, 
15    of functional control to a regional transmission operator, 
16    as defined in Section 16-126, of facilities operating at 
17    69,000 volts and that would otherwise qualify for such 
18    transfer under the applicable rules of the regional 
19    transmission operator taking functional control, or (3) by 
20    any railroad of any real or tangible personal property.    
21        (d) No public utility may by any means, direct or 
22    indirect, merge or consolidate its franchises, licenses, 
23    permits, plants, equipment, business or other property 
24    with that of any other public utility.    
25        (e) No public utility may purchase, acquire, take or 
26    receive any stock, stock certificates, bonds, notes or 
 
 
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1    other evidences of indebtedness of any other public 
2    utility.    
3        (f) No public utility may in any manner, directly or 
4    indirectly, guarantee the performance of any contract or 
5    other obligation of any other person, firm or corporation 
6    whatsoever.    
7        (g) No public utility may use, appropriate, or divert 
8    any of its moneys, property or other resources in or to any 
9    business or enterprise which is not, prior to such use, 
10    appropriation or diversion essentially and directly 
11    connected with or a proper and necessary department or 
12    division of the business of such public utility; provided 
13    that this subsection shall not be construed as modifying 
14    subsections (a) through (e) of this Section.    
15        (h) No public utility may, directly or indirectly, 
16    invest, loan or advance, or permit to be invested, loaned 
17    or advanced any of its moneys, property or other resources 
18    in, for, in behalf of or to any other person, firm, trust, 
19    group, association, company or corporation whatsoever, 
20    except that no consent or approval by the Commission is 
21    necessary for the purchase of stock in development credit 
22    corporations organized under the Illinois Development 
23    Credit Corporation Act, providing that no such purchase 
24    may be made hereunder if, as a result of such purchase, the 
25    cumulative purchase price of all such shares owned by the 
26    utility would exceed one-fiftieth of one per cent of the 
 
 
10400SB0025ham004- 509 -LRB104 16098 AAS 29398 a

1    utility's gross operating revenue for the preceding 
2    calendar year.
3    (B) Any public utility may present to the Commission for 
4approval options or contracts to sell or lease real property, 
5notwithstanding that the value of the property under option 
6may have changed between the date of the option and the 
7subsequent date of sale or lease. If the options or contracts 
8are approved by the Commission, subsequent sales or leases in 
9conformance with those options or contracts may be made by the 
10public utility without any further action by the Commission. 
11If approval of the options or contracts is denied by the 
12Commission, the options or contracts are void and any 
13consideration theretofore paid to the public utility must be 
14refunded within 30 days following disapproval of the 
15application.
16    (C) The proceedings for obtaining the approval of the 
17Commission provided for in this Section shall be as follows: 
18There shall be filed with the Commission a petition, joint or 
19otherwise, as the case may be, signed and verified by the 
20president, any vice president, secretary, treasurer, 
21comptroller, general manager, or chief engineer of the 
22respective companies, or by the person or company, as the case 
23may be, clearly setting forth the object and purposes desired, 
24and setting forth the full and complete terms of the proposed 
25assignment, transfer, lease, mortgage, purchase, sale, merger, 
26consolidation, contract or other transaction, as the case may 
 
 
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1be. Upon the filing of such petition, the Commission shall, if 
2it deems necessary, fix a time and place for the hearing 
3thereon. After such hearing, or in case no hearing is 
4required, if the Commission is satisfied that such petition 
5should reasonably be granted, and that the public will be 
6convenienced thereby, the Commission shall make such order in 
7the premises as it may deem proper and as the circumstances may 
8require, attaching such conditions as it may deem proper, and 
9thereupon it shall be lawful to do the things provided for in 
10such order. The Commission shall impose such conditions as 
11will protect the interest of minority and preferred 
12stockholders.
13    (D) The Commission shall have power by general rules 
14applicable alike to all public utilities, other than electric 
15and gas public utilities, affected thereby to waive the filing 
16and necessity for approval of the following: (a) sales of 
17property involving a consideration of not more than $300,000 
18for utilities with gross revenues in excess of $50,000,000 
19annually and a consideration of not more than $100,000 for all 
20other utilities; (b) leases, easements and licenses involving 
21a consideration or rental of not more than $30,000 per year for 
22utilities with gross revenues in excess of $50,000,000 
23annually and a consideration or rental of not more than 
24$10,000 per year for all other utilities; (c) leases of office 
25building space not required by the public utility in rendering 
26service to the public; (d) the temporary leasing, lending or 
 
 
10400SB0025ham004- 511 -LRB104 16098 AAS 29398 a

1interchanging of equipment in the ordinary course of business 
2or in case of an emergency; and (e) purchase-money mortgages 
3given by a public utility in connection with the purchase of 
4tangible personal property where the total obligation to be 
5secured shall be payable within a period not exceeding one 
6year. However, if the Commission, after a hearing, finds that 
7any public utility to which such rule is applicable is abusing 
8or has abused such general rule and thereby is evading 
9compliance with the standard established herein, the 
10Commission shall have power to require such public utility to 
11thereafter file and receive the Commission's approval upon all 
12such transactions as described in this Section, but such 
13general rule shall remain in full force and effect as to all 
14other public utilities to which such rule is applicable.
15    (E) The filing of, and the consent and approval of the 
16Commission for, any assignment, transfer, lease, mortgage, 
17purchase, sale, merger, consolidation, contract or other 
18transaction by an electric or gas public utility with gross 
19revenues in all jurisdictions of $250,000,000 or more annually 
20involving a sale price or annual consideration in an amount of 
21$5,000,000 or less shall not be required. The Commission shall 
22also have the authority, on petition by an electric or gas 
23public utility with gross revenues in all jurisdictions of 
24$250,000,000 or more annually, to establish by order higher 
25thresholds than the foregoing for the requirement of approval 
26of transactions by the Commission pursuant to this Section for 
 
 
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1the electric or gas public utility, but no greater than 1% of 
2the electric or gas public utility's average total gross 
3utility plant in service in the case of sale, assignment or 
4acquisition of property, or 2.5% of the electric or gas public 
5utility's total revenue in the case of other sales price or 
6annual consideration, in each case based on the preceding 
7calendar year, and subject to the power of the Commission, 
8after notice and hearing, to further revise those thresholds 
9at a later date. In addition to the foregoing, the Commission 
10shall have power by general rules applicable alike to all 
11electric and gas public utilities affected thereby to waive 
12the filing and necessity for approval of the following: (a) 
13sales of property involving a consideration of $100,000 or 
14less for electric and gas utilities with gross revenues in all 
15jurisdictions of less than $250,000,000 annually; (b) leases, 
16easements and licenses involving a consideration or rental of 
17not more than $10,000 per year for electric and gas utilities 
18with gross revenues in all jurisdictions of less than 
19$250,000,000 annually; (c) leases of office building space not 
20required by the electric or gas public utility in rendering 
21service to the public; (d) the temporary leasing, lending or 
22interchanging of equipment in the ordinary course of business 
23or in the case of an emergency; and (e) purchase-money 
24mortgages given by an electric or gas public utility in 
25connection with the purchase of tangible personal property 
26where the total obligation to be secured shall be payable 
 
 
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1within a period of one year or less. However, if the 
2Commission, after a hearing, finds that any electric or gas 
3public utility is abusing or has abused such general rule and 
4thereby is evading compliance with the standard established 
5herein, the Commission shall have power to require such 
6electric or gas public utility to thereafter file and receive 
7the Commission's approval upon all such transactions as 
8described in this Section and not exempted pursuant to the 
9first sentence of this paragraph or to subsection (g) of 
10Section 16-111 of this Act, but such general rule shall remain 
11in full force and effect as to all other electric and gas 
12public utilities.
13    Every assignment, transfer, lease, mortgage, sale or other 
14disposition or encumbrance of the whole or any part of the 
15franchises, licenses, permits, plant, equipment, business or 
16other property of any public utility, or any merger or 
17consolidation thereof, and every contract, purchase of stock, 
18or other transaction referred to in this Section and not 
19exempted in accordance with the provisions of the immediately 
20preceding paragraph of this Section, made otherwise than in 
21accordance with an order of the Commission authorizing the 
22same, except as provided in this Section, shall be void. The 
23provisions of this Section shall not apply to any transactions 
24by or with a political subdivision or municipal corporation of 
25this State.
26    (F) The provisions of this Section do not apply to the 
 
 
10400SB0025ham004- 514 -LRB104 16098 AAS 29398 a

1purchase or sale of emission allowances created under and 
2defined in Title IV of the federal Clean Air Act Amendments of 
31990 (P.L. 101-549), as amended.
4(Source: P.A. 90-561, eff. 12-16-97; 91-357, eff. 7-29-99.)
 
5    (220 ILCS 5/8-101.1 new)
6    Sec. 8-101.1. Duties of public utilities; labor force.
7    (a) As used in this Section:
8    "Labor force" means the employees hired directly by the 
9utility and all employees of any and all suppliers and 
10subcontractors of the utility tasked with the construction, 
11maintenance and repair of such utility's infrastructure.
12    "Public utility" means a public utility, as defined in 
13Section 3-105 of this Act, serving more than 100,000 customers 
14as of January 1, 2025.
15    "Substantial change in labor force" means either (1) a 
16greater than 5% reduction in the total labor force or (2) more 
17than a 5% decrease in the ratio of labor force spending 
18compared to capital spending.
19    (b) A public utility shall ensure that it has the 
20necessary labor force in order to furnish, provide, and 
21maintain such service instrumentalities, equipment, and 
22facilities to promote the safety, health, comfort, and 
23convenience of its patrons, employees, and the public and to 
24be in all respects adequate, efficient, just, and reasonable.
25    (c) Unless the Commission specifically orders and except 
 
 
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1as otherwise provided in this Section, no substantial change 
2shall be made by any public utility in its labor force unless 
3the public utility provides notice to the Commission at least 
445 days before the implementation of the change. A public 
5utility shall include a report with its notice that provides 
6the following:
7        (1) a detailed analysis and explanation of how and why 
8    a change in a specific law, regulation, or market factor 
9    requires the public utility to make the substantial change 
10    in its labor force; and
11        (2) whether the substantial change in the public 
12    utility's labor force, at a minimum:
13            (i) is in the public interest;
14            (ii) will not endanger the quality and 
15        availability of public utility services;
16            (iii) will not have a negative impact on the 
17        safety or reliability of public utility services; and
18            (iv) is designed to minimize the financial 
19        hardship on the members of its labor force impacted by 
20        the substantial change.
 
21    (220 ILCS 5/8-103B)
22    Sec. 8-103B. Energy efficiency and demand-response 
23measures.
24    (a) It is the policy of the State that electric utilities 
25are required to use cost-effective energy efficiency and 
 
 
10400SB0025ham004- 516 -LRB104 16098 AAS 29398 a

1demand-response measures to reduce delivery load. Requiring 
2investment in cost-effective energy efficiency and 
3demand-response measures will reduce direct and indirect costs 
4to consumers by decreasing environmental impacts and by 
5avoiding or delaying the need for new generation, 
6transmission, and distribution infrastructure. It serves the 
7public interest to allow electric utilities to recover costs 
8for reasonably and prudently incurred expenditures for energy 
9efficiency and demand-response measures. As used in this 
10Section, "cost-effective" means that the measures satisfy the 
11total resource cost test. The low-income measures described in 
12subsection (c) of this Section shall not be required to meet 
13the total resource cost test. For purposes of this Section, 
14the terms "energy-efficiency", "demand-response", "electric 
15utility", and "total resource cost test" have the meanings set 
16forth in the Illinois Power Agency Act. "Black, indigenous, 
17and people of color" and "BIPOC" means people who are members 
18of the groups described in subparagraphs (a) through (e) of 
19paragraph (A) of subsection (1) of Section 2 of the Business 
20Enterprise for Minorities, Women, and Persons with 
21Disabilities Act. 
22    (a-5) This Section applies to electric utilities serving 
23more than 500,000 retail customers in the State for those 
24multi-year plans commencing after December 31, 2017. 
25    (b) For purposes of this Section, through calendar year 
262026, electric utilities subject to this Section that serve 
 
 
10400SB0025ham004- 517 -LRB104 16098 AAS 29398 a

1more than 3,000,000 retail customers in the State shall be 
2deemed to have achieved a cumulative persisting annual savings 
3of 6.6% from energy efficiency measures and programs 
4implemented during the period beginning January 1, 2012 and 
5ending December 31, 2017, which percent is based on the deemed 
6average weather normalized sales of electric power and energy 
7during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. 
8For the purposes of this subsection (b) and subsection (b-5), 
9the 88,000,000 MWhs of deemed electric power and energy sales 
10shall be reduced by the number of MWhs equal to the sum of the 
11annual consumption of customers that have opted out of 
12subsections (a) through (j) of this Section under paragraph 
13(1) of subsection (l) of this Section, as averaged across the 
14calendar years 2014, 2015, and 2016. After 2017, the deemed 
15value of cumulative persisting annual savings from energy 
16efficiency measures and programs implemented during the period 
17beginning January 1, 2012 and ending December 31, 2017, shall 
18be reduced each year, as follows, and the applicable value 
19shall be applied to and count toward the utility's achievement 
20of the cumulative persisting annual savings goals set forth in 
21subsection (b-5):
22        (1) 5.8% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2018;
24        (2) 5.2% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2019;
26        (3) 4.5% deemed cumulative persisting annual savings 
 
 
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1    for the year ending December 31, 2020;
2        (4) 4.0% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2021;
4        (5) 3.5% deemed cumulative persisting annual savings 
5    for the year ending December 31, 2022;
6        (6) 3.1% deemed cumulative persisting annual savings 
7    for the year ending December 31, 2023;
8        (7) 2.8% deemed cumulative persisting annual savings 
9    for the year ending December 31, 2024;
10        (8) 2.5% deemed cumulative persisting annual savings 
11    for the year ending December 31, 2025; and    
12        (9) 2.3% deemed cumulative persisting annual savings 
13    for the year ending December 31, 2026. ;
14        (10) 2.1% deemed cumulative persisting annual savings 
15    for the year ending December 31, 2027;
16        (11) 1.8% deemed cumulative persisting annual savings 
17    for the year ending December 31, 2028;
18        (12) 1.7% deemed cumulative persisting annual savings 
19    for the year ending December 31, 2029;
20        (13) 1.5% deemed cumulative persisting annual savings 
21    for the year ending December 31, 2030;
22        (14) 1.3% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2031;
24        (15) 1.1% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2032;
26        (16) 0.9% deemed cumulative persisting annual savings 
 
 
10400SB0025ham004- 519 -LRB104 16098 AAS 29398 a

1    for the year ending December 31, 2033;
2        (17) 0.7% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2034;
4        (18) 0.5% deemed cumulative persisting annual savings 
5    for the year ending December 31, 2035;
6        (19) 0.4% deemed cumulative persisting annual savings 
7    for the year ending December 31, 2036;
8        (20) 0.3% deemed cumulative persisting annual savings 
9    for the year ending December 31, 2037;
10        (21) 0.2% deemed cumulative persisting annual savings 
11    for the year ending December 31, 2038;
12        (22) 0.1% deemed cumulative persisting annual savings 
13    for the year ending December 31, 2039; and
14        (23) 0.0% deemed cumulative persisting annual savings 
15    for the year ending December 31, 2040 and all subsequent 
16    years.    
17    For purposes of this Section, "cumulative persisting 
18annual savings" means the total electric energy savings in a 
19given year from measures installed in that year or in previous 
20years, but no earlier than January 1, 2012, that are still 
21operational and providing savings in that year because the 
22measures have not yet reached the end of their useful lives.
23    (b-5) Beginning in 2018 and through calendar year 2026, 
24electric utilities subject to this Section that serve more 
25than 3,000,000 retail customers in the State shall achieve the 
26following cumulative persisting annual savings goals, as 
 
 
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1modified by subsection (f) of this Section and as compared to 
2the deemed baseline of 88,000,000 MWhs of electric power and 
3energy sales set forth in subsection (b), as reduced by the 
4number of MWhs equal to the sum of the annual consumption of 
5customers that have opted out of subsections (a) through (j) 
6of this Section under paragraph (1) of subsection (l) of this 
7Section as averaged across the calendar years 2014, 2015, and 
82016, through the implementation of energy efficiency measures 
9during the applicable year and in prior years, but no earlier 
10than January 1, 2012:
11        (1) 7.8% cumulative persisting annual savings for the 
12    year ending December 31, 2018;
13        (2) 9.1% cumulative persisting annual savings for the 
14    year ending December 31, 2019;
15        (3) 10.4% cumulative persisting annual savings for the 
16    year ending December 31, 2020;
17        (4) 11.8% cumulative persisting annual savings for the 
18    year ending December 31, 2021;
19        (5) 13.1% cumulative persisting annual savings for the 
20    year ending December 31, 2022;
21        (6) 14.4% cumulative persisting annual savings for the 
22    year ending December 31, 2023;
23        (7) 15.7% cumulative persisting annual savings for the 
24    year ending December 31, 2024;
25        (8) 17% cumulative persisting annual savings for the 
26    year ending December 31, 2025; and    
 
 
10400SB0025ham004- 521 -LRB104 16098 AAS 29398 a

1        (9) 17.9% cumulative persisting annual savings for the 
2    year ending December 31, 2026. ;
3        (10) 18.8% cumulative persisting annual savings for 
4    the year ending December 31, 2027;
5        (11) 19.7% cumulative persisting annual savings for 
6    the year ending December 31, 2028;
7        (12) 20.6% cumulative persisting annual savings for 
8    the year ending December 31, 2029; and
9        (13) 21.5% cumulative persisting annual savings for 
10    the year ending December 31, 2030.
11    No later than December 31, 2021, the Illinois Commerce 
12Commission shall establish additional cumulative persisting 
13annual savings goals for the years 2031 through 2035. No later 
14than December 31, 2024, the Illinois Commerce Commission shall 
15establish additional cumulative persisting annual savings 
16goals for the years 2036 through 2040. The Commission shall 
17also establish additional cumulative persisting annual savings 
18goals every 5 years thereafter to ensure that utilities always 
19have goals that extend at least 11 years into the future. The 
20cumulative persisting annual savings goals beyond the year 
212030 shall increase by 0.9 percentage points per year, absent 
22a Commission decision to initiate a proceeding to consider 
23establishing goals that increase by more or less than that 
24amount. Such a proceeding must be conducted in accordance with 
25the procedures described in subsection (f) of this Section. If 
26such a proceeding is initiated, the cumulative persisting 
 
 
10400SB0025ham004- 522 -LRB104 16098 AAS 29398 a

1annual savings goals established by the Commission through 
2that proceeding shall reflect the Commission's best estimate 
3of the maximum amount of additional savings that are forecast 
4to be cost-effectively achievable unless such best estimates 
5would result in goals that represent less than 0.5 percentage 
6point annual increases in total cumulative persisting annual 
7savings. The Commission may only establish goals that 
8represent less than 0.5 percentage point annual increases in 
9cumulative persisting annual savings if it can demonstrate, 
10based on clear and convincing evidence and through independent 
11analysis, that 0.5 percentage point increases are not 
12cost-effectively achievable. The Commission shall inform its 
13decision based on an energy efficiency potential study that 
14conforms to the requirements of this Section.    
15    (b-10) For purposes of this Section, through calendar year 
162026, electric utilities subject to this Section that serve 
17less than 3,000,000 retail customers but more than 500,000 
18retail customers in the State shall be deemed to have achieved 
19a cumulative persisting annual savings of 6.6% from energy 
20efficiency measures and programs implemented during the period 
21beginning January 1, 2012 and ending December 31, 2017, which 
22is based on the deemed average weather normalized sales of 
23electric power and energy during calendar years 2014, 2015, 
24and 2016 of 36,900,000 MWhs. For the purposes of this 
25subsection (b-10) and subsection (b-15), the 36,900,000 MWhs 
26of deemed electric power and energy sales shall be reduced by 
 
 
10400SB0025ham004- 523 -LRB104 16098 AAS 29398 a

1the number of MWhs equal to the sum of the annual consumption 
2of customers that have opted out of subsections (a) through 
3(j) of this Section under paragraph (1) of subsection (l) of 
4this Section, as averaged across the calendar years 2014, 
52015, and 2016. After 2017, the deemed value of cumulative 
6persisting annual savings from energy efficiency measures and 
7programs implemented during the period beginning January 1, 
82012 and ending December 31, 2017, shall be reduced each year, 
9as follows, and the applicable value shall be applied to and 
10count toward the utility's achievement of the cumulative 
11persisting annual savings goals set forth in subsection 
12(b-15):
13        (1) 5.8% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2018;
15        (2) 5.2% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2019;
17        (3) 4.5% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2020;
19        (4) 4.0% deemed cumulative persisting annual savings 
20    for the year ending December 31, 2021;
21        (5) 3.5% deemed cumulative persisting annual savings 
22    for the year ending December 31, 2022;
23        (6) 3.1% deemed cumulative persisting annual savings 
24    for the year ending December 31, 2023;
25        (7) 2.8% deemed cumulative persisting annual savings 
26    for the year ending December 31, 2024;
 
 
10400SB0025ham004- 524 -LRB104 16098 AAS 29398 a

1        (8) 2.5% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2025; and    
3        (9) 2.3% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2026. ;    
5        (10) 2.1% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2027;
7        (11) 1.8% deemed cumulative persisting annual savings 
8    for the year ending December 31, 2028;
9        (12) 1.7% deemed cumulative persisting annual savings 
10    for the year ending December 31, 2029;
11        (13) 1.5% deemed cumulative persisting annual savings 
12    for the year ending December 31, 2030;
13        (14) 1.3% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2031;
15        (15) 1.1% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2032;
17        (16) 0.9% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2033;
19        (17) 0.7% deemed cumulative persisting annual savings 
20    for the year ending December 31, 2034;
21        (18) 0.5% deemed cumulative persisting annual savings 
22    for the year ending December 31, 2035;
23        (19) 0.4% deemed cumulative persisting annual savings 
24    for the year ending December 31, 2036;
25        (20) 0.3% deemed cumulative persisting annual savings 
26    for the year ending December 31, 2037;
 
 
10400SB0025ham004- 525 -LRB104 16098 AAS 29398 a

1        (21) 0.2% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2038;
3        (22) 0.1% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2039; and
5        (23) 0.0% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2040 and all subsequent 
7    years.    
8    (b-15) Beginning in 2018 and through calendar year 2026, 
9electric utilities subject to this Section that serve less 
10than 3,000,000 retail customers but more than 500,000 retail 
11customers in the State shall achieve the following cumulative 
12persisting annual savings goals, as modified by subsection 
13(b-20) and subsection (f) of this Section and as compared to 
14the deemed baseline as reduced by the number of MWhs equal to 
15the sum of the annual consumption of customers that have opted 
16out of subsections (a) through (j) of this Section under 
17paragraph (1) of subsection (l) of this Section as averaged 
18across the calendar years 2014, 2015, and 2016, through the 
19implementation of energy efficiency measures during the 
20applicable year and in prior years, but no earlier than 
21January 1, 2012:
22        (1) 7.4% cumulative persisting annual savings for the 
23    year ending December 31, 2018;
24        (2) 8.2% cumulative persisting annual savings for the 
25    year ending December 31, 2019;
26        (3) 9.0% cumulative persisting annual savings for the 
 
 
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1    year ending December 31, 2020;
2        (4) 9.8% cumulative persisting annual savings for the 
3    year ending December 31, 2021;
4        (5) 10.6% cumulative persisting annual savings for the 
5    year ending December 31, 2022;
6        (6) 11.4% cumulative persisting annual savings for the 
7    year ending December 31, 2023;
8        (7) 12.2% cumulative persisting annual savings for the 
9    year ending December 31, 2024;
10        (8) 13% cumulative persisting annual savings for the 
11    year ending December 31, 2025; and    
12        (9) 13.6% cumulative persisting annual savings for the 
13    year ending December 31, 2026. ;
14        (10) 14.2% cumulative persisting annual savings for 
15    the year ending December 31, 2027;
16        (11) 14.8% cumulative persisting annual savings for 
17    the year ending December 31, 2028;
18        (12) 15.4% cumulative persisting annual savings for 
19    the year ending December 31, 2029; and
20        (13) 16% cumulative persisting annual savings for the 
21    year ending December 31, 2030.    
22    No later than December 31, 2021, the Illinois Commerce 
23Commission shall establish additional cumulative persisting 
24annual savings goals for the years 2031 through 2035. No later 
25than December 31, 2024, the Illinois Commerce Commission shall 
26establish additional cumulative persisting annual savings 
 
 
10400SB0025ham004- 527 -LRB104 16098 AAS 29398 a

1goals for the years 2036 through 2040. The Commission shall 
2also establish additional cumulative persisting annual savings 
3goals every 5 years thereafter to ensure that utilities always 
4have goals that extend at least 11 years into the future. The 
5cumulative persisting annual savings goals beyond the year 
62030 shall increase by 0.6 percentage points per year, absent 
7a Commission decision to initiate a proceeding to consider 
8establishing goals that increase by more or less than that 
9amount. Such a proceeding must be conducted in accordance with 
10the procedures described in subsection (f) of this Section. If 
11such a proceeding is initiated, the cumulative persisting 
12annual savings goals established by the Commission through 
13that proceeding shall reflect the Commission's best estimate 
14of the maximum amount of additional savings that are forecast 
15to be cost-effectively achievable unless such best estimates 
16would result in goals that represent less than 0.4 percentage 
17point annual increases in total cumulative persisting annual 
18savings. The Commission may only establish goals that 
19represent less than 0.4 percentage point annual increases in 
20cumulative persisting annual savings if it can demonstrate, 
21based on clear and convincing evidence and through independent 
22analysis, that 0.4 percentage point increases are not 
23cost-effectively achievable. The Commission shall inform its 
24decision based on an energy efficiency potential study that 
25conforms to the requirements of this Section.    
26    (b-16) In 2027 and each year thereafter, each electric 
 
 
10400SB0025ham004- 528 -LRB104 16098 AAS 29398 a

1utility subject to this Section shall achieve the following 
2savings goals:
3        (1) A utility that serves more than 3,000,000 retail 
4    customers in the State must achieve incremental annual 
5    energy savings for customers in an amount that is equal to 
6    2% of the utility's average annual electricity sales from 
7    2021 through 2023 to customers. A utility that serves less 
8    than 3,000,000 retail customers but more than 500,000 
9    retail customers in the State must achieve incremental 
10    annual energy savings for customers in an amount that is 
11    equal to 1.4% in 2027, 1.7% in 2028, and 2% in 2029 and 
12    every year thereafter of the utility's average annual 
13    electricity sales from 2021 through 2023 to customers. The 
14    incremental annual energy savings requirements set forth 
15    in this paragraph (1) may be reduced by 0.025 percentage 
16    points for every percentage point increase, above the 25% 
17    minimum to be targeted at low-income households as 
18    specified in paragraph (c) of this Section, in the portion 
19    of total efficiency program spending that is on low-income 
20    or moderate-income efficiency programs. The incremental 
21    annual savings requirement shall not be reduced to a level 
22    less than 0.25 percentage points less than the energy 
23    savings requirement applicable to the calendar year, even 
24    if the sum of low-income spending and moderate-income 
25    spending is greater than 35% of total spending.
26        (2) A utility that serves less than 3,000,000 retail 
 
 
10400SB0025ham004- 529 -LRB104 16098 AAS 29398 a

1    customers but more than 500,000 retail customers in the 
2    State must achieve an incremental annual coincident peak 
3    demand savings goal from energy efficiency measures 
4    installed as a result of the utility's programs by 
5    customers in an amount that is equal to the energy savings 
6    goal from paragraph (1) of this Section divided by the 
7    actual average ratio of kilowatt-hour savings to 
8    coincident peak demand reduction achieved by the utility 
9    through its energy efficiency programs in 2023. If the 
10    season in which coincident peak demands are experienced, 
11    the hours of the day that peak demands are experienced, 
12    and the methods by which peak demand impacts from 
13    efficiency measures are estimated are different in the 
14    future than when 2023 peak demand impacts were originally 
15    estimated, the 2023 peak demand impacts shall be 
16    recomputed using such updated peak definitions and 
17    estimation methods for the purpose of establishing future 
18    coincident peak demand savings goals. To the extent that a 
19    utility counts either improvements to the efficiency of 
20    the use of gas and other fuels or the electrification of 
21    gas and other fuels toward its energy savings goal, as 
22    permitted under paragraphs (b-25) and (b-27) of this 
23    Section, it must estimate the actual impacts on coincident 
24    peak demand from such measures and count them, whether 
25    positive or negative, toward its coincident peak demand 
26    savings goal. Only coincident peak demand savings from 
 
 
10400SB0025ham004- 530 -LRB104 16098 AAS 29398 a

1    efficiency measures shall count toward this goal. To the 
2    extent that some efficiency measures enable demand 
3    response, only the peak demand savings from the energy 
4    efficiency upgrade shall count toward the goal. Nothing in 
5    this Section shall limit the ability of peak demand 
6    savings from such enabled demand-response initiatives to 
7    count for other, non-energy efficiency performance 
8    standard performance metrics established for the utility.
9        (3) Each utility's incremental annual energy savings, 
10    and coincident peak demand savings if a utility serves 
11    less than 3,000,000 retail customers but more than 500,000 
12    retail customers in the State, must be achieved with an 
13    average savings life of at least 12 years. In no event can 
14    more than one-fifth of the incremental annual savings or 
15    the coincident peak demand savings counted toward a 
16    utility's annual savings goal in any given year be derived 
17    from efficiency measures with average savings lives of 
18    less than 5 years. Average savings lives may be shorter 
19    than the average operational lives of measures installed 
20    if the measures do not produce savings in every year in 
21    which the measures operate or if the savings that measures 
22    produce decline during the measures' operational lives.
23            For the purposes of this Section, "incremental annual 
24    energy savings" means the total electric energy savings 
25    from all measures installed in a calendar year that will 
26    be realized within 12 months of each measure's 
 
 
10400SB0025ham004- 531 -LRB104 16098 AAS 29398 a

1    installation; "moderate-income" means income between 80% 
2    of area median income and 300% of the federal poverty 
3    limit; "incremental annual coincident peak demand savings" 
4    means the total coincident peak reduction from all energy 
5    efficiency measures installed in a calendar year that will 
6    be realized within 12 months of each measure's 
7    installation; "average savings life" means the lifetime 
8    savings that would be realized as a result of a utility's 
9    efficiency programs divided by the incremental annual 
10    savings such programs produce.    
11    (b-20) Each electric utility subject to this Section may 
12include cost-effective voltage optimization measures in its 
13plans submitted under subsections (f) and (g) of this Section, 
14and the costs incurred by a utility to implement the measures 
15under a Commission-approved plan shall be recovered under the 
16provisions of Article IX or Section 16-108.5 of this Act. For 
17purposes of this Section, the measure life of voltage 
18optimization measures shall be 15 years. The measure life 
19period is independent of the depreciation rate of the voltage 
20optimization assets deployed. Utilities may claim savings from 
21voltage optimization on circuits for more than 15 years if 
22they can demonstrate that they have made additional 
23investments necessary to enable voltage optimization savings 
24to continue beyond 15 years. Such demonstrations must be 
25subject to the review of independent evaluation. 
26    Within 270 days after June 1, 2017 (the effective date of 
 
 
10400SB0025ham004- 532 -LRB104 16098 AAS 29398 a

1Public Act 99-906), an electric utility that serves less than 
23,000,000 retail customers but more than 500,000 retail 
3customers in the State shall file a plan with the Commission 
4that identifies the cost-effective voltage optimization 
5investment the electric utility plans to undertake through 
6December 31, 2024. The Commission, after notice and hearing, 
7shall approve or approve with modification the plan within 120 
8days after the plan's filing and, in the order approving or 
9approving with modification the plan, the Commission shall 
10adjust the applicable cumulative persisting annual savings 
11goals set forth in subsection (b-15) to reflect any amount of 
12cost-effective energy savings approved by the Commission that 
13is greater than or less than the following cumulative 
14persisting annual savings values attributable to voltage 
15optimization for the applicable year:
16        (1) 0.0% of cumulative persisting annual savings for 
17    the year ending December 31, 2018;
18        (2) 0.17% of cumulative persisting annual savings for 
19    the year ending December 31, 2019;
20        (3) 0.17% of cumulative persisting annual savings for 
21    the year ending December 31, 2020;
22        (4) 0.33% of cumulative persisting annual savings for 
23    the year ending December 31, 2021;
24        (5) 0.5% of cumulative persisting annual savings for 
25    the year ending December 31, 2022;
26        (6) 0.67% of cumulative persisting annual savings for 
 
 
10400SB0025ham004- 533 -LRB104 16098 AAS 29398 a

1    the year ending December 31, 2023;
2        (7) 0.83% of cumulative persisting annual savings for 
3    the year ending December 31, 2024; and
4        (8) 1.0% of cumulative persisting annual savings for 
5    the year ending December 31, 2025 and all subsequent 
6    years. 
7    (b-25) In the event an electric utility jointly offers an 
8energy efficiency measure or program with a gas utility under 
9plans approved under this Section and Section 8-104 of this 
10Act, the electric utility may continue offering the program, 
11including the gas energy efficiency measures, in the event the 
12gas utility discontinues funding the program. In that event, 
13the energy savings value associated with such other fuels 
14shall be converted to electric energy savings on an equivalent 
15Btu basis for the premises. However, the electric utility 
16shall prioritize programs for low-income residential customers 
17to the extent practicable. An electric utility may recover the 
18costs of offering the gas energy efficiency measures under 
19this subsection (b-25).
20    For those energy efficiency measures or programs that save 
21both electricity and other fuels but are not jointly offered 
22with a gas utility under plans approved under this Section and 
23Section 8-104 or not offered with an affiliated gas utility 
24under paragraph (6) of subsection (f) of Section 8-104 of this 
25Act, the electric utility may count savings of fuels other 
26than electricity toward the achievement of its annual savings 
 
 
10400SB0025ham004- 534 -LRB104 16098 AAS 29398 a

1goal, and the energy savings value associated with such other 
2fuels shall be converted to electric energy savings on an 
3equivalent Btu basis at the premises. 
4    For an electric utility that serves more than 3,000,000 
5retail customers in the State, on and after January 1, 2027, 
6the electric utility may only count savings of other fuels 
7under this subsection (b-25) toward the achievement of its 
8annual electric energy savings goal when such other fuel 
9savings are from weatherization measures that reduce heat loss 
10through the building envelope, insulating mechanical systems, 
11or the heating distribution system, including, but not limited 
12to, air sealing and building shell measures. This limitation 
13on counting other fuel savings from efficiency measures toward 
14a utility's energy savings goal shall not affect the utility's 
15ability to claim savings from electrification measures 
16installed pursuant to the requirements in subsection (b-27).    
17    In no event shall more than 10% of each year's applicable 
18annual total savings requirement, as defined in paragraph 
19(7.5) of subsection (g) of this Section be met through savings 
20of fuels other than electricity. For an electric utility that 
21serves more than 3,000,000 retail customers in the State, in 
22no event shall more than 30% of each year's incremental annual 
23energy savings requirement, as defined in subsection (b-16) of 
24this Section, be met through savings of fuels other than 
25electricity. For an electric utility that serves less than 
263,000,000 retail customers but more than 500,000 retail 
 
 
10400SB0025ham004- 535 -LRB104 16098 AAS 29398 a

1customers in the State, in no event shall more than 20% of each 
2year's incremental annual energy savings requirement, as 
3defined in subsection (b-16) of this Section, be met through 
4savings of fuels other than electricity.    
5    (b-27) Beginning in 2022, an electric utility may offer 
6and promote measures that electrify space heating, water 
7heating, cooling, drying, cooking, industrial processes, and 
8other building and industrial end uses that would otherwise be 
9served by combustion of fossil fuel at the premises, provided 
10that the electrification measures reduce total energy 
11consumption at the premises. The electric utility may count 
12the reduction in energy consumption at the premises toward 
13achievement of its annual savings goals. The reduction in 
14energy consumption at the premises shall be calculated as the 
15difference between: (A) the reduction in Btu consumption of 
16fossil fuels as a result of electrification, converted to 
17kilowatt-hour equivalents by dividing by 3,412 Btus per 
18kilowatt hour; and (B) the increase in kilowatt hours of 
19electricity consumption resulting from the displacement of 
20fossil fuel consumption as a result of electrification. An 
21electric utility may recover the costs of offering and 
22promoting electrification measures under this subsection 
23(b-27).
24    At least 33% of all costs of offering and promoting 
25electrification measures under this subsection (b-27) must be 
26for supporting installation of electrification measures 
 
 
10400SB0025ham004- 536 -LRB104 16098 AAS 29398 a

1through programs exclusively targeted to low-income 
2households. The percentage requirement may be reduced if the 
3utility can demonstrate that it is not possible to achieve the 
4level of low-income electrification spending, while supporting 
5programs for non-low-income residential and business 
6electrification, because of limitations regarding the number 
7of low-income households in its service territory that would 
8be able to meet program eligibility requirements set forth in 
9the multi-year energy efficiency plan. If the 33% low-income 
10electrification spending requirement is reduced, the utility 
11must prioritize support of low-income electrification in 
12housing that meets program eligibility requirements over 
13electrification spending on non-low-income residential or 
14business customers.
15    The ratio of spending on electrification measures targeted 
16to low-income, multifamily buildings to spending on 
17electrification measures targeted to low-income, single-family 
18buildings shall be designed to achieve levels of 
19electrification savings from each building type that are 
20approximately proportional to the magnitude of cost-effective 
21electrification savings potential in each building type.    
22    In no event shall electrification savings counted toward 
23each year's applicable annual total savings requirement, as 
24defined in paragraph (7.5) of subsection (g) of this Section, 
25or counted toward each year's incremental annual savings, as 
26defined in paragraph (b-16) of this Section, be greater than:
 
 
10400SB0025ham004- 537 -LRB104 16098 AAS 29398 a

1        (1) 5% per year for each year from 2022 through 2025;
2        (2) 20% 10% per year for each year from 2026 and all 
3    subsequent years through 2029; and
4        (3) (blank). 15% per year for 2030 and all subsequent 
5    years.
6In addition, a minimum of 25% of all electrification savings 
7counted toward a utility's applicable annual total savings 
8requirement must be from electrification of end uses in 
9low-income housing. The limitations on electrification savings 
10that may be counted toward a utility's annual savings goals 
11are separate from and in addition to the subsection (b-25) 
12limitations governing the counting of the other fuel savings 
13resulting from efficiency measures and programs.
14    As part of the annual informational filing to the 
15Commission that is required under paragraph (9) of subsection 
16(g) of this Section, each utility shall identify the specific 
17electrification measures offered under this subsection (b-27); 
18the quantity of each electrification measure that was 
19installed by its customers; the average total cost, average 
20utility cost, average reduction in fossil fuel consumption, 
21and average increase in electricity consumption associated 
22with each electrification measure; the portion of 
23installations of each electrification measure that were in 
24low-income single-family housing, low-income multifamily 
25housing, non-low-income single-family housing, non-low-income 
26multifamily housing, commercial buildings, and industrial 
 
 
10400SB0025ham004- 538 -LRB104 16098 AAS 29398 a

1facilities; and the quantity of savings associated with each 
2measure category in each customer category that are being 
3counted toward the utility's applicable annual total savings 
4requirement or counted toward each year's incremental annual 
5savings, as defined in paragraph (b-16) of this Section. Prior 
6to installing or promoting an electrification measures    
7measure, the utility shall provide customers a customer with 
8estimates an estimate of the impact of the new measures    
9measure on the customer's average monthly electric bill and 
10total annual energy expenses. 
11    (c) Electric utilities shall be responsible for overseeing 
12the design, development, and filing of energy efficiency plans 
13with the Commission and may, as part of that implementation, 
14outsource various aspects of program development and 
15implementation. A minimum of 10%, for electric utilities that 
16serve more than 3,000,000 retail customers in the State, and a 
17minimum of 7%, for electric utilities that serve less than 
183,000,000 retail customers but more than 500,000 retail 
19customers in the State, of the utility's entire portfolio 
20funding level for a given year shall be used to procure 
21cost-effective energy efficiency measures from units of local 
22government, municipal corporations, school districts, public 
23housing, public institutions of higher education, and 
24community college districts, provided that a minimum 
25percentage of available funds shall be used to procure energy 
26efficiency from public housing, which percentage shall be 
 
 
10400SB0025ham004- 539 -LRB104 16098 AAS 29398 a

1equal to public housing's share of public building energy 
2consumption.
3    The utilities shall also implement energy efficiency 
4measures targeted at low-income households, which, for 
5purposes of this Section, shall be defined as households at or 
6below 80% of area median income, and expenditures to implement 
7the measures shall be no less than 25% of total energy 
8efficiency program spending approved by the Commission 
9pursuant to review of plans filed under subsection (f) of this 
10Section $40,000,000 per year for electric utilities that serve 
11more than 3,000,000 retail customers in the State and no less 
12than $13,000,000 per year for electric utilities that serve 
13less than 3,000,000 retail customers but more than 500,000 
14retail customers in the State. The ratio of spending on 
15efficiency programs targeted at low-income multifamily 
16buildings to spending on efficiency programs targeted at 
17low-income single-family buildings shall be designed to 
18achieve levels of savings from each building type that are 
19approximately proportional to the magnitude of cost-effective 
20lifetime savings potential in each building type. Investment 
21in low-income whole-building weatherization programs shall 
22constitute a minimum of 80% of a utility's total budget 
23specifically dedicated to serving low-income customers.
24    The utilities shall work to bundle low-income energy 
25efficiency offerings with other programs that serve low-income 
26households to maximize the benefits going to these households. 
 
 
10400SB0025ham004- 540 -LRB104 16098 AAS 29398 a

1The utilities shall market and implement low-income energy 
2efficiency programs in coordination with low-income assistance 
3programs, the Illinois Solar for All Program, and 
4weatherization whenever practicable. The program implementer 
5shall walk the customer through the enrollment process for any 
6programs for which the customer is eligible. The utilities 
7shall also pilot targeting customers with high arrearages, 
8high energy intensity (ratio of energy usage divided by home 
9or unit square footage), or energy assistance programs with 
10energy efficiency offerings, and then track reduction in 
11arrearages as a result of the targeting. This targeting and 
12bundling of low-income energy programs shall be offered to 
13both low-income single-family and multifamily customers 
14(owners and residents). 
15    The utilities shall invest in health and safety measures 
16appropriate and necessary for comprehensively weatherizing a 
17home or multifamily building, and shall implement a health and 
18safety fund of at least 15% of the total income-qualified 
19weatherization budget that shall be used for the purpose of 
20making grants for technical assistance, construction, 
21reconstruction, improvement, or repair of buildings to 
22facilitate their participation in the energy efficiency 
23programs targeted at low-income single-family and multifamily 
24households. These funds may also be used for the purpose of 
25making grants for technical assistance, construction, 
26reconstruction, improvement, or repair of the following 
 
 
10400SB0025ham004- 541 -LRB104 16098 AAS 29398 a

1buildings to facilitate their participation in the energy 
2efficiency programs created by this Section: (1) buildings 
3that are owned or operated by registered 501(c)(3) public 
4charities; and (2) day care centers, day care homes, or group 
5day care homes, as defined under 89 Ill. Adm. Code Part 406, 
6407, or 408, respectively. 
7    Each electric utility shall assess opportunities to 
8implement cost-effective energy efficiency measures and 
9programs through a public housing authority or authorities 
10located in its service territory. If such opportunities are 
11identified, the utility shall propose such measures and 
12programs to address the opportunities. Expenditures to address 
13such opportunities shall be credited toward the minimum 
14procurement and expenditure requirements set forth in this 
15subsection (c).
16    Implementation of energy efficiency measures and programs 
17targeted at low-income households should be contracted, when 
18it is practicable, to independent third parties that have 
19demonstrated capabilities to serve such households, with a 
20preference for not-for-profit entities and government agencies 
21that have existing relationships with or experience serving 
22low-income communities in the State.
23    Each electric utility shall develop and implement 
24reporting procedures that address and assist in determining 
25the amount of energy savings that can be applied to the 
26low-income procurement and expenditure requirements set forth 
 
 
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1in this subsection (c). Each electric utility shall also track 
2the types and quantities or volumes of insulation and air 
3sealing materials, and their associated energy saving 
4benefits, installed in energy efficiency programs targeted at 
5low-income single-family and multifamily households. 
6    The electric utilities shall participate in a low-income 
7energy efficiency accountability committee ("the committee"), 
8which will directly inform the design, implementation, and 
9evaluation of the low-income and public-housing energy 
10efficiency programs. The committee shall be comprised of the 
11electric utilities subject to the requirements of this 
12Section, the gas utilities subject to the requirements of 
13Section 8-104 of this Act, the utilities' low-income energy 
14efficiency implementation contractors, nonprofit 
15organizations, community action agencies, advocacy groups, 
16State and local governmental agencies, public-housing 
17organizations, and representatives of community-based 
18organizations, especially those living in or working with 
19environmental justice communities and BIPOC communities. The 
20committee shall be composed of 2 geographically differentiated 
21subcommittees: one for stakeholders in northern Illinois and 
22one for stakeholders in central and southern Illinois. The 
23subcommittees shall meet together at least twice per year.
24    There shall be one statewide leadership committee led by 
25and composed of community-based organizations that are 
26representative of BIPOC and environmental justice communities 
 
 
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1and that includes equitable representation from BIPOC 
2communities. The leadership committee shall be composed of an 
3equal number of representatives from the 2 subcommittees. The 
4subcommittees shall address specific programs and issues, with 
5the leadership committee convening targeted workgroups as 
6needed. The leadership committee may elect to work with an 
7independent facilitator to solicit and organize feedback, 
8recommendations and meeting participation from a wide variety 
9of community-based stakeholders. If a facilitator is used, 
10they shall be fair and responsive to the needs of all 
11stakeholders involved in the committee. For a utility that 
12serves more than 3,000,000 retail customers in the State, if a 
13facilitator is used, they shall be retained by Commission 
14staff.    
15     All committee meetings must be accessible, with rotating 
16locations if meetings are held in-person, virtual 
17participation options, and materials and agendas circulated in 
18advance.
19    There shall also be opportunities for direct input by 
20committee members outside of committee meetings, such as via 
21individual meetings, surveys, emails and calls, to ensure 
22robust participation by stakeholders with limited capacity and 
23ability to attend committee meetings. Committee meetings shall 
24emphasize opportunities to bundle and coordinate delivery of 
25low-income energy efficiency with other programs that serve 
26low-income communities, such as the Illinois Solar for All 
 
 
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1Program and bill payment assistance programs. Meetings shall 
2include educational opportunities for stakeholders to learn 
3more about these additional offerings, and the committee shall 
4assist in figuring out the best methods for coordinated 
5delivery and implementation of offerings when serving 
6low-income communities. The committee shall directly and 
7equitably influence and inform utility low-income and 
8public-housing energy efficiency programs and priorities. 
9Participating utilities shall implement recommendations from 
10the committee whenever possible.
11    Participating utilities shall track and report how input 
12from the committee has led to new approaches and changes in 
13their energy efficiency portfolios. This reporting shall occur 
14at committee meetings and in quarterly energy efficiency 
15reports to the Stakeholder Advisory Group and Illinois 
16Commerce Commission, and other relevant reporting mechanisms. 
17Participating utilities shall also report on relevant equity 
18data and metrics requested by the committee, such as energy 
19burden data, geographic, racial, and other relevant 
20demographic data on where programs are being delivered and 
21what populations programs are serving.
22    The Illinois Commerce Commission shall oversee and have 
23relevant staff participate in the committee. The committee 
24shall have a budget of 0.25% of each utility's entire 
25efficiency portfolio funding for a given year. The budget 
26shall be overseen by the Commission. The budget shall be used 
 
 
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1to provide grants for community-based organizations serving on 
2the leadership committee, stipends for community-based 
3organizations participating in the committee, grants for 
4community-based organizations to do energy efficiency outreach 
5and education, and relevant meeting needs as determined by the 
6leadership committee. The education and outreach shall 
7include, but is not limited to, basic energy efficiency 
8education, information about low-income energy efficiency 
9programs, and information on the committee's purpose, 
10structure, and activities.
11    (d) Notwithstanding any other provision of law to the 
12contrary, a utility providing approved energy efficiency 
13measures and, if applicable, demand-response measures in the 
14State shall be permitted to recover all reasonable and 
15prudently incurred costs of those measures from all retail 
16customers, except as provided in subsection (l) of this 
17Section, as follows, provided that nothing in this subsection 
18(d) permits the double recovery of such costs from customers: 
19        (1) The utility may recover its costs through an 
20    automatic adjustment clause tariff filed with and approved 
21    by the Commission. The tariff shall be established outside 
22    the context of a general rate case. Each year the 
23    Commission shall initiate a review to reconcile any 
24    amounts collected with the actual costs and to determine 
25    the required adjustment to the annual tariff factor to 
26    match annual expenditures. To enable the financing of the 
 
 
10400SB0025ham004- 546 -LRB104 16098 AAS 29398 a

1    incremental capital expenditures, including regulatory 
2    assets, for electric utilities that serve less than 
3    3,000,000 retail customers but more than 500,000 retail 
4    customers in the State, the utility's actual year-end 
5    capital structure that includes a common equity ratio, 
6    excluding goodwill, of up to and including 50% of the 
7    total capital structure shall be deemed reasonable and 
8    used to set rates.
9        (2) A utility may recover its costs through an energy 
10    efficiency formula rate approved by the Commission under a 
11    filing under subsections (f) and (g) of this Section, 
12    which shall specify the cost components that form the 
13    basis of the rate charged to customers with sufficient 
14    specificity to operate in a standardized manner and be 
15    updated annually with transparent information that 
16    reflects the utility's actual costs to be recovered during 
17    the applicable rate year, which is the period beginning 
18    with the first billing day of January and extending 
19    through the last billing day of the following December. 
20    The energy efficiency formula rate shall be implemented 
21    through a tariff filed with the Commission under 
22    subsections (f) and (g) of this Section that is consistent 
23    with the provisions of this paragraph (2) and that shall 
24    be applicable to all delivery services customers. The 
25    Commission shall conduct an investigation of the tariff in 
26    a manner consistent with the provisions of this paragraph 
 
 
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1    (2), subsections (f) and (g) of this Section, and the 
2    provisions of Article IX of this Act to the extent they do 
3    not conflict with this paragraph (2). The energy 
4    efficiency formula rate approved by the Commission shall 
5    remain in effect at the discretion of the utility and 
6    shall do the following:
7            (A) Provide for the recovery of the utility's 
8        actual costs incurred under this Section that are 
9        prudently incurred and reasonable in amount consistent 
10        with Commission practice and law. The sole fact that a 
11        cost differs from that incurred in a prior calendar 
12        year or that an investment is different from that made 
13        in a prior calendar year shall not imply the 
14        imprudence or unreasonableness of that cost or 
15        investment.
16            (B) Reflect the utility's actual year-end capital 
17        structure for the applicable calendar year, excluding 
18        goodwill, subject to a determination of prudence and 
19        reasonableness consistent with Commission practice and 
20        law. To enable the financing of the incremental 
21        capital expenditures, including regulatory assets, for 
22        electric utilities that serve less than 3,000,000 
23        retail customers but more than 500,000 retail 
24        customers in the State, a participating electric 
25        utility's actual year-end capital structure that 
26        includes a common equity ratio, excluding goodwill, of 
 
 
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1        up to and including 50% of the total capital structure 
2        shall be deemed reasonable and used to set rates.
3            (C) Include a cost of equity that shall be equal to 
4        the baseline cost of equity approved by the Commission 
5        for the utility's electric distribution rates 
6        effective during the applicable year, whether those 
7        rates are set pursuant to Section 9-201, subparagraph 
8        (B) of paragraph (3) of subsection (d) of Section 
9        16-108.18, or any successor electric distribution 
10        ratemaking paradigm. , which shall be calculated as the 
11        sum of the following:
12                (i) the average for the applicable calendar 
13            year of the monthly average yields of 30-year U.S. 
14            Treasury bonds published by the Board of Governors 
15            of the Federal Reserve System in its weekly H.15 
16            Statistical Release or successor publication; and
17                (ii) 580 basis points.
18            At such time as the Board of Governors of the 
19        Federal Reserve System ceases to include the monthly 
20        average yields of 30-year U.S. Treasury bonds in its 
21        weekly H.15 Statistical Release or successor 
22        publication, the monthly average yields of the U.S. 
23        Treasury bonds then having the longest duration 
24        published by the Board of Governors in its weekly H.15 
25        Statistical Release or successor publication shall 
26        instead be used for purposes of this paragraph (2).
 
 
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1            (D) Permit and set forth protocols, subject to a 
2        determination of prudence and reasonableness 
3        consistent with Commission practice and law, for the 
4        following:
5                (i) recovery of incentive compensation expense 
6            that is based on the achievement of operational 
7            metrics, including metrics related to budget 
8            controls, outage duration and frequency, safety, 
9            customer service, efficiency and productivity, and 
10            environmental compliance; however, this protocol 
11            shall not apply if such expense related to costs 
12            incurred under this Section is recovered under 
13            Article IX or Section 16-108.5 of this Act; 
14            incentive compensation expense that is based on 
15            net income or an affiliate's earnings per share 
16            shall not be recoverable under the energy 
17            efficiency formula rate;
18                (ii) recovery of pension and other 
19            post-employment benefits expense, provided that 
20            such costs are supported by an actuarial study; 
21            however, this protocol shall not apply if such 
22            expense related to costs incurred under this 
23            Section is recovered under Article IX or Section 
24            16-108.5 of this Act;
25                (iii) recovery of existing regulatory assets 
26            over the periods previously authorized by the 
 
 
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1            Commission;
2                (iv) as described in subsection (e), 
3            amortization of costs incurred under this Section; 
4            and
5                (v) projected, weather normalized billing 
6            determinants for the applicable rate year.
7            (E) Provide for an annual reconciliation, as 
8        described in paragraph (3) of this subsection (d), 
9        less any deferred taxes related to the reconciliation, 
10        with interest at an annual rate of return equal to the 
11        utility's weighted average cost of capital, including 
12        a revenue conversion factor calculated to recover or 
13        refund all additional income taxes that may be payable 
14        or receivable as a result of that return, of the energy 
15        efficiency revenue requirement reflected in rates for 
16        each calendar year, beginning with the calendar year 
17        in which the utility files its energy efficiency 
18        formula rate tariff under this paragraph (2), with 
19        what the revenue requirement would have been had the 
20        actual cost information for the applicable calendar 
21        year been available at the filing date.
22        The utility shall file, together with its tariff, the 
23    projected costs to be incurred by the utility during the 
24    rate year under the utility's multi-year plan approved 
25    under subsections (f) and (g) of this Section, including, 
26    but not limited to, the projected capital investment costs 
 
 
10400SB0025ham004- 551 -LRB104 16098 AAS 29398 a

1    and projected regulatory asset balances with 
2    correspondingly updated depreciation and amortization 
3    reserves and expense, that shall populate the energy 
4    efficiency formula rate and set the initial rates under 
5    the formula.
6        The Commission shall review the proposed tariff in 
7    conjunction with its review of a proposed multi-year plan, 
8    as specified in paragraph (5) of subsection (g) of this 
9    Section. The review shall be based on the same evidentiary 
10    standards, including, but not limited to, those concerning 
11    the prudence and reasonableness of the costs incurred by 
12    the utility, the Commission applies in a hearing to review 
13    a filing for a general increase in rates under Article IX 
14    of this Act. The initial rates shall take effect beginning 
15    with the January monthly billing period following the 
16    Commission's approval.
17        The tariff's rate design and cost allocation across 
18    customer classes shall be consistent with the utility's 
19    automatic adjustment clause tariff in effect on June 1, 
20    2017 (the effective date of Public Act 99-906); however, 
21    the Commission may revise the tariff's rate design and 
22    cost allocation in subsequent proceedings under paragraph 
23    (3) of this subsection (d).
24        If the energy efficiency formula rate is terminated, 
25    the then current rates shall remain in effect until such 
26    time as the energy efficiency costs are incorporated into 
 
 
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1    new rates that are set under this subsection (d) or 
2    Article IX of this Act, subject to retroactive rate 
3    adjustment, with interest, to reconcile rates charged with 
4    actual costs.
5        (3) The provisions of this paragraph (3) shall only 
6    apply to an electric utility that has elected to file an 
7    energy efficiency formula rate under paragraph (2) of this 
8    subsection (d). Subsequent to the Commission's issuance of 
9    an order approving the utility's energy efficiency formula 
10    rate structure and protocols, and initial rates under 
11    paragraph (2) of this subsection (d), the utility shall 
12    file, on or before June 1 of each year, with the Chief 
13    Clerk of the Commission its updated cost inputs to the 
14    energy efficiency formula rate for the applicable rate 
15    year and the corresponding new charges, as well as the 
16    information described in paragraph (9) of subsection (g) 
17    of this Section. Each such filing shall conform to the 
18    following requirements and include the following 
19    information:
20            (A) The inputs to the energy efficiency formula 
21        rate for the applicable rate year shall be based on the 
22        projected costs to be incurred by the utility during 
23        the rate year under the utility's multi-year plan 
24        approved under subsections (f) and (g) of this 
25        Section, including, but not limited to, projected 
26        capital investment costs and projected regulatory 
 
 
10400SB0025ham004- 553 -LRB104 16098 AAS 29398 a

1        asset balances with correspondingly updated 
2        depreciation and amortization reserves and expense. 
3        The filing shall also include a reconciliation of the 
4        energy efficiency revenue requirement that was in 
5        effect for the prior rate year (as set by the cost 
6        inputs for the prior rate year) with the actual 
7        revenue requirement for the prior rate year 
8        (determined using a year-end rate base) that uses 
9        amounts reflected in the applicable FERC Form 1 that 
10        reports the actual costs for the prior rate year. Any 
11        over-collection or under-collection indicated by such 
12        reconciliation shall be reflected as a credit against, 
13        or recovered as an additional charge to, respectively, 
14        with interest calculated at a rate equal to the 
15        utility's weighted average cost of capital approved by 
16        the Commission for the prior rate year, the charges 
17        for the applicable rate year. Such over-collection or 
18        under-collection shall be adjusted to remove any 
19        deferred taxes related to the reconciliation, for 
20        purposes of calculating interest at an annual rate of 
21        return equal to the utility's weighted average cost of 
22        capital approved by the Commission for the prior rate 
23        year, including a revenue conversion factor calculated 
24        to recover or refund all additional income taxes that 
25        may be payable or receivable as a result of that 
26        return. Each reconciliation shall be certified by the 
 
 
10400SB0025ham004- 554 -LRB104 16098 AAS 29398 a

1        participating utility in the same manner that FERC 
2        Form 1 is certified. The filing shall also include the 
3        charge or credit, if any, resulting from the 
4        calculation required by subparagraph (E) of paragraph 
5        (2) of this subsection (d).
6            Notwithstanding any other provision of law to the 
7        contrary, the intent of the reconciliation is to 
8        ultimately reconcile both the revenue requirement 
9        reflected in rates for each calendar year, beginning 
10        with the calendar year in which the utility files its 
11        energy efficiency formula rate tariff under paragraph 
12        (2) of this subsection (d), with what the revenue 
13        requirement determined using a year-end rate base for 
14        the applicable calendar year would have been had the 
15        actual cost information for the applicable calendar 
16        year been available at the filing date.
17            For purposes of this Section, "FERC Form 1" means 
18        the Annual Report of Major Electric Utilities, 
19        Licensees and Others that electric utilities are 
20        required to file with the Federal Energy Regulatory 
21        Commission under the Federal Power Act, Sections 3, 
22        4(a), 304 and 209, modified as necessary to be 
23        consistent with 83 Ill. Adm. Code Part 415 as of May 1, 
24        2011. Nothing in this Section is intended to allow 
25        costs that are not otherwise recoverable to be 
26        recoverable by virtue of inclusion in FERC Form 1.
 
 
10400SB0025ham004- 555 -LRB104 16098 AAS 29398 a

1            (B) The new charges shall take effect beginning on 
2        the first billing day of the following January billing 
3        period and remain in effect through the last billing 
4        day of the next December billing period regardless of 
5        whether the Commission enters upon a hearing under 
6        this paragraph (3).
7            (C) The filing shall include relevant and 
8        necessary data and documentation for the applicable 
9        rate year. Normalization adjustments shall not be 
10        required.
11        Within 45 days after the utility files its annual 
12    update of cost inputs to the energy efficiency formula 
13    rate, the Commission shall with reasonable notice, 
14    initiate a proceeding concerning whether the projected 
15    costs to be incurred by the utility and recovered during 
16    the applicable rate year, and that are reflected in the 
17    inputs to the energy efficiency formula rate, are 
18    consistent with the utility's approved multi-year plan 
19    under subsections (f) and (g) of this Section and whether 
20    the costs incurred by the utility during the prior rate 
21    year were prudent and reasonable. The Commission shall 
22    also have the authority to investigate the information and 
23    data described in paragraph (9) of subsection (g) of this 
24    Section, including the proposed adjustment to the 
25    utility's return on equity component of its weighted 
26    average cost of capital. During the course of the 
 
 
10400SB0025ham004- 556 -LRB104 16098 AAS 29398 a

1    proceeding, each objection shall be stated with 
2    particularity and evidence provided in support thereof, 
3    after which the utility shall have the opportunity to 
4    rebut the evidence. Discovery shall be allowed consistent 
5    with the Commission's Rules of Practice, which Rules of 
6    Practice shall be enforced by the Commission or the 
7    assigned administrative law judge. The Commission shall 
8    apply the same evidentiary standards, including, but not 
9    limited to, those concerning the prudence and 
10    reasonableness of the costs incurred by the utility, 
11    during the proceeding as it would apply in a proceeding to 
12    review a filing for a general increase in rates under 
13    Article IX of this Act. The Commission shall not, however, 
14    have the authority in a proceeding under this paragraph 
15    (3) to consider or order any changes to the structure or 
16    protocols of the energy efficiency formula rate approved 
17    under paragraph (2) of this subsection (d). In a 
18    proceeding under this paragraph (3), the Commission shall 
19    enter its order no later than the earlier of 195 days after 
20    the utility's filing of its annual update of cost inputs 
21    to the energy efficiency formula rate or December 15. The 
22    utility's proposed return on equity calculation, as 
23    described in paragraphs (7) through (9) of subsection (g) 
24    of this Section, shall be deemed the final, approved 
25    calculation on December 15 of the year in which it is filed 
26    unless the Commission enters an order on or before 
 
 
10400SB0025ham004- 557 -LRB104 16098 AAS 29398 a

1    December 15, after notice and hearing, that modifies such 
2    calculation consistent with this Section. The Commission's 
3    determinations of the prudence and reasonableness of the 
4    costs incurred, and determination of such return on equity 
5    calculation, for the applicable calendar year shall be 
6    final upon entry of the Commission's order and shall not 
7    be subject to reopening, reexamination, or collateral 
8    attack in any other Commission proceeding, case, docket, 
9    order, rule, or regulation; however, nothing in this 
10    paragraph (3) shall prohibit a party from petitioning the 
11    Commission to rehear or appeal to the courts the order 
12    under the provisions of this Act.
13    (e) Beginning on June 1, 2017 (the effective date of 
14Public Act 99-906), a utility subject to the requirements of 
15this Section may elect to defer, as a regulatory asset, up to 
16the full amount of its expenditures incurred under this 
17Section for each annual period, including, but not limited to, 
18any expenditures incurred above the funding level set by 
19subsection (f) of this Section for a given year. The total 
20expenditures deferred as a regulatory asset in a given year 
21shall be amortized and recovered over a period that is equal to 
22the weighted average of the energy efficiency measure lives 
23implemented for that year that are reflected in the regulatory 
24asset. The unamortized balance shall be recognized as of 
25December 31 for a given year. The utility shall also earn a 
26return on the total of the unamortized balances of all of the 
 
 
10400SB0025ham004- 558 -LRB104 16098 AAS 29398 a

1energy efficiency regulatory assets, less any deferred taxes 
2related to those unamortized balances, at an annual rate equal 
3to the utility's weighted average cost of capital that 
4includes, based on a year-end capital structure, the utility's 
5actual cost of debt for the applicable calendar year and a cost 
6of equity, which shall be determined as set forth in 
7subparagraph (C) of paragraph (2) of subsection of this 
8Section calculated as the sum of the (i) the average for the 
9applicable calendar year of the monthly average yields of 
1030-year U.S. Treasury bonds published by the Board of 
11Governors of the Federal Reserve System in its weekly H.15 
12Statistical Release or successor publication; and (ii) 580 
13basis points, including a revenue conversion factor calculated 
14to recover or refund all additional income taxes that may be 
15payable or receivable as a result of that return. Capital 
16investment costs shall be depreciated and recovered over their 
17useful lives consistent with generally accepted accounting 
18principles. The weighted average cost of capital shall be 
19applied to the capital investment cost balance, less any 
20accumulated depreciation and accumulated deferred income 
21taxes, as of December 31 for a given year.
22    When an electric utility creates a regulatory asset under 
23the provisions of this Section, the costs are recovered over a 
24period during which customers also receive a benefit which is 
25in the public interest. Accordingly, it is the intent of the 
26General Assembly that an electric utility that elects to 
 
 
10400SB0025ham004- 559 -LRB104 16098 AAS 29398 a

1create a regulatory asset under the provisions of this Section 
2shall recover all of the associated costs as set forth in this 
3Section. After the Commission has approved the prudence and 
4reasonableness of the costs that comprise the regulatory 
5asset, the electric utility shall be permitted to recover all 
6such costs, and the value and recoverability through rates of 
7the associated regulatory asset shall not be limited, altered, 
8impaired, or reduced.
9    (f) Beginning in 2017, each electric utility shall file an 
10energy efficiency plan with the Commission to meet the energy 
11efficiency standards for the next applicable multi-year period 
12beginning January 1 of the year following the filing, 
13according to the schedule set forth in paragraphs (1) through 
14(3) of this subsection (f). If a utility does not file such a 
15plan on or before the applicable filing deadline for the plan, 
16it shall face a penalty of $100,000 per day until the plan is 
17filed.
18        (1) No later than 30 days after June 1, 2017 (the 
19    effective date of Public Act 99-906), each electric 
20    utility shall file a 4-year energy efficiency plan 
21    commencing on January 1, 2018 that is designed to achieve 
22    the cumulative persisting annual savings goals specified 
23    in paragraphs (1) through (4) of subsection (b-5) of this 
24    Section or in paragraphs (1) through (4) of subsection 
25    (b-15) of this Section, as applicable, through 
26    implementation of energy efficiency measures; however, the 
 
 
10400SB0025ham004- 560 -LRB104 16098 AAS 29398 a

1    goals may be reduced if the utility's expenditures are 
2    limited pursuant to subsection (m) of this Section or, for 
3    a utility that serves less than 3,000,000 retail 
4    customers, if each of the following conditions are met: 
5    (A) the plan's analysis and forecasts of the utility's 
6    ability to acquire energy savings demonstrate that 
7    achievement of such goals is not cost effective; and (B) 
8    the amount of energy savings achieved by the utility as 
9    determined by the independent evaluator for the most 
10    recent year for which savings have been evaluated 
11    preceding the plan filing was less than the average annual 
12    amount of savings required to achieve the goals for the 
13    applicable 4-year plan period. Except as provided in 
14    subsection (m) of this Section, annual increases in 
15    cumulative persisting annual savings goals during the 
16    applicable 4-year plan period shall not be reduced to 
17    amounts that are less than the maximum amount of 
18    cumulative persisting annual savings that is forecast to 
19    be cost-effectively achievable during the 4-year plan 
20    period. The Commission shall review any proposed goal 
21    reduction as part of its review and approval of the 
22    utility's proposed plan.
23        (2) No later than March 1, 2021, each electric utility 
24    shall file a 4-year energy efficiency plan commencing on 
25    January 1, 2022 that is designed to achieve the cumulative 
26    persisting annual savings goals specified in paragraphs 
 
 
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1    (5) through (8) of subsection (b-5) of this Section or in 
2    paragraphs (5) through (8) of subsection (b-15) of this 
3    Section, as applicable, through implementation of energy 
4    efficiency measures; however, the goals may be reduced if 
5    either (1) clear and convincing evidence demonstrates, 
6    through independent analysis, that the expenditure limits 
7    in subsection (m) of this Section preclude full 
8    achievement of the goals or (2) each of the following 
9    conditions are met: (A) the plan's analysis and forecasts 
10    of the utility's ability to acquire energy savings 
11    demonstrate by clear and convincing evidence and through 
12    independent analysis that achievement of such goals is not 
13    cost effective; and (B) the amount of energy savings 
14    achieved by the utility as determined by the independent 
15    evaluator for the most recent year for which savings have 
16    been evaluated preceding the plan filing was less than the 
17    average annual amount of savings required to achieve the 
18    goals for the applicable 4-year plan period. If there is 
19    not clear and convincing evidence that achieving the 
20    savings goals specified in paragraph (b-5) or (b-15) of 
21    this Section is possible both cost-effectively and within 
22    the expenditure limits in subsection (m), such savings 
23    goals shall not be reduced. Except as provided in 
24    subsection (m) of this Section, annual increases in 
25    cumulative persisting annual savings goals during the 
26    applicable 4-year plan period shall not be reduced to 
 
 
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1    amounts that are less than the maximum amount of 
2    cumulative persisting annual savings that is forecast to 
3    be cost-effectively achievable during the 4-year plan 
4    period. The Commission shall review any proposed goal 
5    reduction as part of its review and approval of the 
6    utility's proposed plan.
7        (2.5) Provisions of the multi-year plans for calendar 
8    years 2026 through 2029 that relate to calendar year 2026 
9    and that were filed by the electric utilities on February 
10    28, 2025 shall remain in effect through calendar year 
11    2026. Provisions of the plans for calendar years 2027 
12    through 2029 shall be modified and resubmitted to the 
13    Commission by the electric utilities pursuant to paragraph 
14    (3) of this subsection (f).    
15        (3) No later than the effective date of this 
16    amendatory Act of the 104th General Assembly March 1, 
17    2025, each electric utility shall file a 3-year 4-year    
18    energy efficiency plan commencing on January 1, 2027 2026    
19    that is designed to achieve, through implementation of 
20    energy efficiency measures, lifetime energy equal to the 
21    product of the incremental annual savings goals defined by 
22    paragraph (1) of subsection (b-16) and the minimum average 
23    savings life defined by paragraph (3) of subsection 
24    (b-16). The 3-year energy efficiency plan of a utility 
25    that serves less than 3,000,000 retail customers but more 
26    than 500,000 retail customers in the State must also be 
 
 
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1    designed to achieve lifetime peak demand savings equal to 
2    the product of the incremental annual savings goals 
3    defined by paragraph (2) of subsection (b-16) and the 
4    minimum average savings life defined by paragraph (3) of 
5    subsection (b-16) through implementation of energy 
6    efficiency measures. The savings goals may be reduced if: 
7    (i) clear and convincing evidence and independent analysis 
8    demonstrates that the expenditure limits in subsection (m) 
9    of this Section preclude full achievement of the goals, 
10    (ii) each of the following conditions are met: (A) the 
11    plan's analysis and forecasts of the utility's ability to 
12    acquire energy savings demonstrate by clear and convincing 
13    evidence and through independent analysis that achievement 
14    of such goals is not cost-effective; and (B) the amount of 
15    energy savings achieved by the utility, as determined by 
16    the independent evaluator, for the most recent year for 
17    which savings have been evaluated preceding the plan 
18    filing was less than the average annual amount of savings 
19    required to achieve the goals for the applicable 
20    multi-year plan period, or (iii) changes in federal law, 
21    programs, or tariffs have a significant and demonstrable 
22    impact on the cost of delivering measures and programs. If 
23    there is not clear and convincing evidence that achieving 
24    the savings goals specified in subsection (b-16) is not 
25    possible both cost-effectively and within the expenditure 
26    limits in subsection (m), such savings goals shall not be 
 
 
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1    reduced. Except as provided in subsection (m), annual 
2    savings goals during the applicable multi-year plan period 
3    shall not be reduced to amounts that are less than the 
4    maximum amount of annual savings that is forecasted to be 
5    cost-effectively achievable during the applicable 
6    multi-year plan period. The Commission shall review any 
7    proposed goal reduction as part of its review and approval 
8    of the utility's proposed plan. the cumulative persisting 
9    annual savings goals specified in paragraphs (9) through 
10    (12) of subsection (b-5) of this Section or in paragraphs 
11    (9) through (12) of subsection (b-15) of this Section, as 
12    applicable, through implementation of energy efficiency 
13    measures; however, the goals may be reduced if either (1) 
14    clear and convincing evidence demonstrates, through 
15    independent analysis, that the expenditure limits in 
16    subsection (m) of this Section preclude full achievement 
17    of the goals or (2) each of the following conditions are 
18    met: (A) the plan's analysis and forecasts of the 
19    utility's ability to acquire energy savings demonstrate by 
20    clear and convincing evidence and through independent 
21    analysis that achievement of such goals is not cost 
22    effective; and (B) the amount of energy savings achieved 
23    by the utility as determined by the independent evaluator 
24    for the most recent year for which savings have been 
25    evaluated preceding the plan filing was less than the 
26    average annual amount of savings required to achieve the 
 
 
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1    goals for the applicable 4-year plan period. If there is 
2    not clear and convincing evidence that achieving the 
3    savings goals specified in paragraphs (b-5) or (b-15) of 
4    this Section is possible both cost-effectively and within 
5    the expenditure limits in subsection (m), such savings 
6    goals shall not be reduced. Except as provided in 
7    subsection (m) of this Section, annual increases in 
8    cumulative persisting annual savings goals during the 
9    applicable 4-year plan period shall not be reduced to 
10    amounts that are less than the maximum amount of 
11    cumulative persisting annual savings that is forecast to 
12    be cost-effectively achievable during the 4-year plan 
13    period. The Commission shall review any proposed goal 
14    reduction as part of its review and approval of the 
15    utility's proposed plan.    
16        (4) No later than March 1, 2029, and every 4 years 
17    thereafter, each electric utility shall file a 4-year 
18    energy efficiency plan commencing on January 1, 2030, and 
19    every 4 years thereafter, respectively, that is designed 
20    to achieve the cumulative persisting annual savings goals 
21    established by the Illinois Commerce Commission pursuant 
22    to direction of subsections (b-5) and (b-15) of this 
23    Section, as applicable, through implementation of energy 
24    efficiency measures, lifetime energy equal to the product 
25    of the incremental annual savings goals defined by 
26    paragraph (1) of subsection (b-16) and the minimum average 
 
 
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1    savings life described in paragraph (C) of subsection 
2    (b-16) of this Section. The multi-year energy efficiency 
3    plan of a utility that serves less than 3,000,000 retail 
4    customers but more than 500,000 retail customers in the 
5    State must also be designed to achieve lifetime peak 
6    demand savings equal to the product of the incremental 
7    annual savings goals defined by paragraph (2) of 
8    subsection (b-16) and the minimum average savings life 
9    defined by paragraph (3) of subsection (b-16) through 
10    implementation of energy efficiency measures. However ; 
11    however, the goals may be reduced if: either (1) clear and 
12    convincing evidence and independent analysis demonstrates 
13    that the expenditure limits in subsection (m) of this 
14    Section preclude full achievement of the goals; or (2) 
15    each of the following conditions are met: (A) the plan's 
16    analysis and forecasts of the utility's ability to acquire 
17    energy savings demonstrate by clear and convincing 
18    evidence and through independent analysis that achievement 
19    of such goals is not cost-effective; and (B) the amount of 
20    energy savings achieved by the utility as determined by 
21    the independent evaluator for the most recent year for 
22    which savings have been evaluated preceding the plan 
23    filing was less than the average annual amount of savings 
24    required to achieve the goals for the applicable 
25    multi-year 4-year plan period; or (3) changes in federal 
26    law, programs, or tariffs have a significant and 
 
 
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1    demonstrable impact on the cost of delivering measures and 
2    programs. If there is not clear and convincing evidence 
3    that achieving the savings goals specified in paragraph 
4    (b-16) paragraphs (b-5) or (b-15) of this Section is 
5    possible both cost-effectively and within the expenditure 
6    limits in subsection (m), such savings goals shall not be 
7    reduced. Except as provided in subsection (m) of this 
8    Section, annual increases in cumulative persisting annual 
9    savings goals during the applicable multi-year 4-year plan 
10    period shall not be reduced to amounts that are less than 
11    the maximum amount of cumulative persisting annual savings 
12    that is forecast to be cost-effectively achievable during 
13    the applicable multi-year 4-year plan period. The 
14    Commission shall review any proposed goal reduction as 
15    part of its review and approval of the utility's proposed 
16    plan.
17    Each utility's plan shall set forth the utility's 
18proposals to meet the energy efficiency standards identified 
19in subsection (b-5), or (b-15), or (b-16), as applicable and 
20as such standards may have been modified under this subsection 
21(f), taking into account the unique circumstances of the 
22utility's service territory. For those plans commencing on 
23January 1, 2018, the Commission shall seek public comment on 
24the utility's plan and shall issue an order approving or 
25disapproving each plan no later than 105 days after June 1, 
262017 (the effective date of Public Act 99-906). For those 
 
 
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1plans commencing after December 31, 2021, the Commission shall 
2seek public comment on the utility's plan and shall issue an 
3order approving or disapproving each plan within 6 months 
4after its submission. If the Commission disapproves a plan, 
5the Commission shall, within 30 days, describe in detail the 
6reasons for the disapproval and describe a path by which the 
7utility may file a revised draft of the plan to address the 
8Commission's concerns satisfactorily. If the utility does not 
9refile with the Commission within 60 days, the utility shall 
10be subject to penalties at a rate of $100,000 per day until the 
11plan is filed. This process shall continue, and penalties 
12shall accrue, until the utility has successfully filed a 
13portfolio of energy efficiency and demand-response measures. 
14Penalties shall be deposited into the Energy Efficiency Trust 
15Fund. 
16    (g) In submitting proposed plans and funding levels under 
17subsection (f) of this Section to meet the savings goals 
18identified in subsection (b-5), or (b-15), or (b-16) of this 
19Section, as applicable, the utility shall:
20        (1) Demonstrate that its proposed energy efficiency 
21    measures will achieve the applicable requirements that are 
22    identified in subsection (b-5), or (b-15), or (b-16) of 
23    this Section, as modified by subsection (f) of this 
24    Section.
25        (2) (Blank).
26        (2.5) Demonstrate consideration of program options for 
 
 
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1    (A) advancing new building codes, appliance standards, and 
2    municipal regulations governing existing and new building 
3    efficiency improvements and (B) supporting efforts to 
4    improve compliance with new building codes, appliance 
5    standards and municipal regulations, as potentially 
6    cost-effective means of acquiring energy savings to count 
7    toward savings goals. 
8        (3) Demonstrate that its overall portfolio of 
9    measures, not including low-income programs described in 
10    subsection (c) of this Section, is cost-effective using 
11    the total resource cost test or complies with paragraphs 
12    (1) through (3) of subsection (f) of this Section and 
13    represents a diverse cross-section of opportunities for 
14    customers of all rate classes, other than those customers 
15    described in subsection (l) of this Section, to 
16    participate in the programs. Individual measures need not 
17    be cost effective.
18        (3.5) Demonstrate that the utility's plan integrates 
19    the delivery of energy efficiency programs with natural 
20    gas efficiency programs, programs promoting distributed 
21    solar, programs promoting demand response and other 
22    efforts to address bill payment issues, including, but not 
23    limited to, LIHEAP and the Percentage of Income Payment 
24    Plan, to the extent such integration is practical and has 
25    the potential to enhance customer engagement, minimize 
26    market confusion, or reduce administrative costs. 
 
 
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1        (4) If the utility chooses, present Present a 
2    third-party energy efficiency implementation program 
3    subject to the following requirements:
4            (A) (blank); beginning with the year commencing 
5        January 1, 2019, electric utilities that serve more 
6        than 3,000,000 retail customers in the State shall 
7        fund third-party energy efficiency programs in an 
8        amount that is no less than $25,000,000 per year, and 
9        electric utilities that serve less than 3,000,000 
10        retail customers but more than 500,000 retail 
11        customers in the State shall fund third-party energy 
12        efficiency programs in an amount that is no less than 
13        $8,350,000 per year;
14            (B) during 2018, the utility shall conduct a 
15        solicitation process for purposes of requesting 
16        proposals from third-party vendors for those 
17        third-party energy efficiency programs to be offered 
18        during one or more of the years commencing January 1, 
19        2019, January 1, 2020, and January 1, 2021; for those 
20        multi-year plans commencing on January 1, 2022 and 
21        January 1, 2026, the utility shall conduct a 
22        solicitation process during 2021 and 2025, 
23        respectively, for purposes of requesting proposals 
24        from third-party vendors for those third-party energy 
25        efficiency programs to be offered during one or more 
26        years of the respective multi-year plan period; for 
 
 
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1        each solicitation process, the utility shall identify 
2        the sector, technology, or geographical area for which 
3        it is seeking requests for proposals; the solicitation 
4        process must be either for programs that fill gaps in 
5        the utility's program portfolio and for programs that 
6        target low-income customers, business sectors, 
7        building types, geographies, or other specific parts 
8        of its customer base with initiatives that would be 
9        more effective at reaching these customer segments 
10        than the utilities' programs filed in its energy 
11        efficiency plans;
12            (C) the utility shall propose the bidder 
13        qualifications, performance measurement process, and 
14        contract structure, which must include a performance 
15        payment mechanism and general terms and conditions; 
16        the proposed qualifications, process, and structure 
17        shall be subject to Commission approval; and
18            (D) the utility shall retain an independent third 
19        party to score the proposals received through the 
20        solicitation process described in this paragraph (4), 
21        rank them according to their cost per lifetime 
22        kilowatt-hours saved, and assemble the portfolio of 
23        third-party programs.
24        The electric utility shall recover all costs 
25    associated with Commission-approved, third-party 
26    administered programs regardless of the success of those 
 
 
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1    programs. 
2        (4.5) Implement cost-effective demand-response 
3    measures to reduce peak demand by 0.1% over the prior year 
4    for eligible retail customers, as defined in Section 
5    16-111.5 of this Act, and for customers that elect hourly 
6    service from the utility pursuant to Section 16-107 of 
7    this Act, provided those customers have not been declared 
8    competitive. This requirement continues until December 31, 
9    2026. 
10        (5) Include a proposed or revised cost-recovery tariff 
11    mechanism, as provided for under subsection (d) of this 
12    Section, to fund the proposed energy efficiency and 
13    demand-response measures and to ensure the recovery of the 
14    prudently and reasonably incurred costs of 
15    Commission-approved programs.
16        (6) Provide for an annual independent evaluation of 
17    the performance of the cost-effectiveness of the utility's 
18    portfolio of measures, as well as a full review of the 
19    multi-year plan results of the broader net program impacts 
20    and, to the extent practical, for adjustment of the 
21    measures on a going-forward basis as a result of the 
22    evaluations. The resources dedicated to evaluation shall 
23    not exceed 3% of portfolio resources in any given year.
24        (7) For electric utilities that serve more than 
25    3,000,000 retail customers in the State:
26            (A) Through December 31, 2026 2025, provide for an 
 
 
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1        adjustment to the return on equity component of the 
2        utility's weighted average cost of capital calculated 
3        under subsection (d) of this Section:
4                (i) If the independent evaluator determines 
5            that the utility achieved a cumulative persisting 
6            annual savings that is less than the applicable 
7            annual incremental goal, then the return on equity 
8            component shall be reduced by a maximum of 200 
9            basis points in the event that the utility 
10            achieved no more than 75% of such goal. If the 
11            utility achieved more than 75% of the applicable 
12            annual incremental goal but less than 100% of such 
13            goal, then the return on equity component shall be 
14            reduced by 8 basis points for each percent by 
15            which the utility failed to achieve the goal.
16                (ii) If the independent evaluator determines 
17            that the utility achieved a cumulative persisting 
18            annual savings that is more than the applicable 
19            annual incremental goal, then the return on equity 
20            component shall be increased by a maximum of 200 
21            basis points in the event that the utility 
22            achieved at least 125% of such goal. If the 
23            utility achieved more than 100% of the applicable 
24            annual incremental goal but less than 125% of such 
25            goal, then the return on equity component shall be 
26            increased by 8 basis points for each percent by 
 
 
10400SB0025ham004- 574 -LRB104 16098 AAS 29398 a

1            which the utility achieved above the goal. If the 
2            applicable annual incremental goal was reduced 
3            under paragraph (1) or (2) of subsection (f) of 
4            this Section, then the following adjustments shall 
5            be made to the calculations described in this item 
6            (ii):
7                    (aa) the calculation for determining 
8                achievement that is at least 125% of the 
9                applicable annual incremental goal shall use 
10                the unreduced applicable annual incremental 
11                goal to set the value; and
12                    (bb) the calculation for determining 
13                achievement that is less than 125% but more 
14                than 100% of the applicable annual incremental 
15                goal shall use the reduced applicable annual 
16                incremental goal to set the value for 100% 
17                achievement of the goal and shall use the 
18                unreduced goal to set the value for 125% 
19                achievement. The 8 basis point value shall 
20                also be modified, as necessary, so that the 
21                200 basis points are evenly apportioned among 
22                each percentage point value between 100% and 
23                125% achievement.
24            (B) (Blank). For the period January 1, 2026 
25        through December 31, 2029 and in all subsequent 4-year 
26        periods, provide for an adjustment to the return on 
 
 
10400SB0025ham004- 575 -LRB104 16098 AAS 29398 a

1        equity component of the utility's weighted average 
2        cost of capital calculated under subsection (d) of 
3        this Section:
4                (i) If the independent evaluator determines 
5            that the utility achieved a cumulative persisting 
6            annual savings that is less than the applicable 
7            annual incremental goal, then the return on equity 
8            component shall be reduced by a maximum of 200 
9            basis points in the event that the utility 
10            achieved no more than 66% of such goal. If the 
11            utility achieved more than 66% of the applicable 
12            annual incremental goal but less than 100% of such 
13            goal, then the return on equity component shall be 
14            reduced by 6 basis points for each percent by 
15            which the utility failed to achieve the goal.
16                (ii) If the independent evaluator determines 
17            that the utility achieved a cumulative persisting 
18            annual savings that is more than the applicable 
19            annual incremental goal, then the return on equity 
20            component shall be increased by a maximum of 200 
21            basis points in the event that the utility 
22            achieved at least 134% of such goal. If the 
23            utility achieved more than 100% of the applicable 
24            annual incremental goal but less than 134% of such 
25            goal, then the return on equity component shall be 
26            increased by 6 basis points for each percent by 
 
 
10400SB0025ham004- 576 -LRB104 16098 AAS 29398 a

1            which the utility achieved above the goal. If the 
2            applicable annual incremental goal was reduced 
3            under paragraph (3) of subsection (f) of this 
4            Section, then the following adjustments shall be 
5            made to the calculations described in this item 
6            (ii):
7                    (aa) the calculation for determining 
8                achievement that is at least 134% of the 
9                applicable annual incremental goal shall use 
10                the unreduced applicable annual incremental 
11                goal to set the value; and
12                    (bb) the calculation for determining 
13                achievement that is less than 134% but more 
14                than 100% of the applicable annual incremental 
15                goal shall use the reduced applicable annual 
16                incremental goal to set the value for 100% 
17                achievement of the goal and shall use the 
18                unreduced goal to set the value for 134% 
19                achievement. The 6 basis point value shall 
20                also be modified, as necessary, so that the 
21                200 basis points are evenly apportioned among 
22                each percentage point value between 100% and 
23                134% achievement. 
24            (C) (Blank). Notwithstanding the provisions of 
25        subparagraphs (A) and (B) of this paragraph (7), if 
26        the applicable annual incremental goal for an electric 
 
 
10400SB0025ham004- 577 -LRB104 16098 AAS 29398 a

1        utility is ever less than 0.6% of deemed average 
2        weather normalized sales of electric power and energy 
3        during calendar years 2014, 2015, and 2016, an 
4        adjustment to the return on equity component of the 
5        utility's weighted average cost of capital calculated 
6        under subsection (d) of this Section shall be made as 
7        follows:
8                (i) If the independent evaluator determines 
9            that the utility achieved a cumulative persisting 
10            annual savings that is less than would have been 
11            achieved had the applicable annual incremental 
12            goal been achieved, then the return on equity 
13            component shall be reduced by a maximum of 200 
14            basis points if the utility achieved no more than 
15            75% of its applicable annual total savings 
16            requirement as defined in paragraph (7.5) of this 
17            subsection. If the utility achieved more than 75% 
18            of the applicable annual total savings requirement 
19            but less than 100% of such goal, then the return on 
20            equity component shall be reduced by 8 basis 
21            points for each percent by which the utility 
22            failed to achieve the goal.
23                (ii) If the independent evaluator determines 
24            that the utility achieved a cumulative persisting 
25            annual savings that is more than would have been 
26            achieved had the applicable annual incremental 
 
 
10400SB0025ham004- 578 -LRB104 16098 AAS 29398 a

1            goal been achieved, then the return on equity 
2            component shall be increased by a maximum of 200 
3            basis points if the utility achieved at least 125% 
4            of its applicable annual total savings 
5            requirement. If the utility achieved more than 
6            100% of the applicable annual total savings 
7            requirement but less than 125% of such goal, then 
8            the return on equity component shall be increased 
9            by 8 basis points for each percent by which the 
10            utility achieved above the applicable annual total 
11            savings requirement. If the applicable annual 
12            incremental goal was reduced under paragraph (1) 
13            or (2) of subsection (f) of this Section, then the 
14            following adjustments shall be made to the 
15            calculations described in this item (ii):
16                    (aa) the calculation for determining 
17                achievement that is at least 125% of the 
18                applicable annual total savings requirement 
19                shall use the unreduced applicable annual 
20                incremental goal to set the value; and
21                    (bb) the calculation for determining 
22                achievement that is less than 125% but more 
23                than 100% of the applicable annual total 
24                savings requirement shall use the reduced 
25                applicable annual incremental goal to set the 
26                value for 100% achievement of the goal and 
 
 
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1                shall use the unreduced goal to set the value 
2                for 125% achievement. The 8 basis point value 
3                shall also be modified, as necessary, so that 
4                the 200 basis points are evenly apportioned 
5                among each percentage point value between 100% 
6                and 125% achievement. 
7        (7.5) For purposes of this Section, the term 
8    "applicable annual incremental goal" means the difference 
9    between the cumulative persisting annual savings goal for 
10    the calendar year that is the subject of the independent 
11    evaluator's determination and the cumulative persisting 
12    annual savings goal for the immediately preceding calendar 
13    year, as such goals are defined in subsections (b-5) and 
14    (b-15) of this Section and as these goals may have been 
15    modified as provided for under subsection (b-20) and 
16    paragraphs (1) and (2) through (3) of subsection (f) of 
17    this Section. Under subsections (b), (b-5), (b-10), and 
18    (b-15) of this Section, a utility must first replace 
19    energy savings from measures that have expired before any 
20    progress towards achievement of its applicable annual 
21    incremental goal may be counted. Savings may expire 
22    because measures installed in previous years have reached 
23    the end of their lives, because measures installed in 
24    previous years are producing lower savings in the current 
25    year than in the previous year, or for other reasons 
26    identified by independent evaluators. Notwithstanding 
 
 
10400SB0025ham004- 580 -LRB104 16098 AAS 29398 a

1    anything else set forth in this Section, the difference 
2    between the actual annual incremental savings achieved in 
3    any given year, including the replacement of energy 
4    savings that have expired, and the applicable annual 
5    incremental goal shall not affect adjustments to the 
6    return on equity for subsequent calendar years under this 
7    subsection (g). 
8        In this Section, "applicable annual total savings 
9    requirement" means the total amount of new annual savings 
10    that the utility must achieve in any given year to achieve 
11    the applicable annual incremental goal. This is equal to 
12    the applicable annual incremental goal plus the total new 
13    annual savings that are required to replace savings that 
14    expired in or at the end of the previous year. 
15        (8) For electric utilities that serve less than 
16    3,000,000 retail customers but more than 500,000 retail 
17    customers in the State:
18            (A) Through December 31, 2026 2025, the applicable 
19        annual incremental goal shall be compared to the 
20        annual incremental savings as determined by the 
21        independent evaluator.
22                (i) The return on equity component shall be 
23            reduced by 8 basis points for each percent by 
24            which the utility did not achieve 84.4% of the 
25            applicable annual incremental goal.
26                (ii) The return on equity component shall be 
 
 
10400SB0025ham004- 581 -LRB104 16098 AAS 29398 a

1            increased by 8 basis points for each percent by 
2            which the utility exceeded 100% of the applicable 
3            annual incremental goal.
4                (iii) The return on equity component shall not 
5            be increased or decreased if the annual 
6            incremental savings as determined by the 
7            independent evaluator is greater than 84.4% of the 
8            applicable annual incremental goal and less than 
9            100% of the applicable annual incremental goal.
10                (iv) The return on equity component shall not 
11            be increased or decreased by an amount greater 
12            than 200 basis points pursuant to this 
13            subparagraph (A).
14            (B) (Blank). For the period of January 1, 2026 
15        through December 31, 2029 and in all subsequent 4-year 
16        periods, the applicable annual incremental goal shall 
17        be compared to the annual incremental savings as 
18        determined by the independent evaluator.
19                (i) The return on equity component shall be 
20            reduced by 6 basis points for each percent by 
21            which the utility did not achieve 100% of the 
22            applicable annual incremental goal.
23                (ii) The return on equity component shall be 
24            increased by 6 basis points for each percent by 
25            which the utility exceeded 100% of the applicable 
26            annual incremental goal.
 
 
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1                (iii) The return on equity component shall not 
2            be increased or decreased by an amount greater 
3            than 200 basis points pursuant to this 
4            subparagraph (B).
5            (C) (Blank). Notwithstanding provisions in 
6        subparagraphs (A) and (B) of paragraph (7) of this 
7        subsection, if the applicable annual incremental goal 
8        for an electric utility is ever less than 0.6% of 
9        deemed average weather normalized sales of electric 
10        power and energy during calendar years 2014, 2015 and 
11        2016, an adjustment to the return on equity component 
12        of the utility's weighted average cost of capital 
13        calculated under subsection (d) of this Section shall 
14        be made as follows:
15                (i) The return on equity component shall be 
16            reduced by 8 basis points for each percent by 
17            which the utility did not achieve 100% of the 
18            applicable annual total savings requirement.
19                (ii) The return on equity component shall be 
20            increased by 8 basis points for each percent by 
21            which the utility exceeded 100% of the applicable 
22            annual total savings requirement.
23                (iii) The return on equity component shall not 
24            be increased or decreased by an amount greater 
25            than 200 basis points pursuant to this 
26            subparagraph (C). 
 
 
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1            (D) (Blank). If the applicable annual incremental 
2        goal was reduced under paragraph (1), (2), (3), or (4) 
3        of subsection (f) of this Section, then the following 
4        adjustments shall be made to the calculations 
5        described in subparagraphs (A), (B), and (C) of this 
6        paragraph (8):
7                (i) The calculation for determining 
8            achievement that is at least 125% or 134%, as 
9            applicable, of the applicable annual incremental 
10            goal or the applicable annual total savings 
11            requirement, as applicable, shall use the 
12            unreduced applicable annual incremental goal to 
13            set the value.
14                (ii) For the period through December 31, 2025, 
15            the calculation for determining achievement that 
16            is less than 125% but more than 100% of the 
17            applicable annual incremental goal or the 
18            applicable annual total savings requirement, as 
19            applicable, shall use the reduced applicable 
20            annual incremental goal to set the value for 100% 
21            achievement of the goal and shall use the 
22            unreduced goal to set the value for 125% 
23            achievement. The 8 basis point value shall also be 
24            modified, as necessary, so that the 200 basis 
25            points are evenly apportioned among each 
26            percentage point value between 100% and 125% 
 
 
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1            achievement.
2                (iii) For the period of January 1, 2026 
3            through December 31, 2029 and all subsequent 
4            4-year periods, the calculation for determining 
5            achievement that is less than 125% or 134%, as 
6            applicable, but more than 100% of the applicable 
7            annual incremental goal or the applicable annual 
8            total savings requirement, as applicable, shall 
9            use the reduced applicable annual incremental goal 
10            to set the value for 100% achievement of the goal 
11            and shall use the unreduced goal to set the value 
12            for 125% achievement. The 6 basis-point value or 8 
13            basis-point value, as applicable, shall also be 
14            modified, as necessary, so that the 200 basis 
15            points are evenly apportioned among each 
16            percentage point value between 100% and 125% or 
17            between 100% and 134% achievement, as applicable.
18        (8.5) Beginning January 1, 2027, a utility that serves 
19    greater than 500,000 retail customers in the State shall 
20    have the utility's return on equity modified for 
21    performance on the utility's energy savings and peak 
22    demand savings goals as follows:
23            (A) The return on equity for a utility that serves 
24        more than 3,000,000 retail customers in the State may 
25        be adjusted up or down by a maximum of 200 basis points 
26        for its performance relative to its incremental annual 
 
 
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1        energy savings goal. The return on equity for a 
2        utility that serves less than 3,000,000 retail 
3        customers but more than 500,000 retail customers in 
4        the State may be adjusted up or down by a maximum of 
5        100 basis points for its performance relative to its 
6        incremental annual energy savings goal and a maximum 
7        of 100 basis points for its performance relative to 
8        its incremental annual coincident peak demand savings 
9        goal.
10            (B) A utility's performance on its savings goals 
11        shall be established by comparing the actual lifetime 
12        energy, and coincident peak demand savings if a 
13        utility serves less than 3,000,000 retail customers 
14        but more than 500,000 retail customers in the State, 
15        achieved from efficiency measures installed in a given 
16        year to the product of the incremental annual goals 
17        established in paragraphs (1) and (2) of subsection 
18        (b-16) and the minimum average savings lives 
19        established in paragraph (3) of subsection (b-16), as 
20        modified, if applicable, by the Commission under 
21        paragraph (4) of subsection (f) of this Section. For 
22        the purposes of this paragraph (8.5), "lifetime 
23        savings" means the total incremental savings that 
24        installed efficiency measures are projected to 
25        produce, relative to what would have occurred absent 
26        to the utility's efficiency programs, over the useful 
 
 
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1        lives of the measures. Performance on the energy 
2        savings goal, and coincident peak demand savings if a 
3        utility serves less than 3,000,000 retail customers 
4        but more than 500,000 retail customers in the State, 
5        shall be assessed separately, such that it is possible 
6        to earn penalties on both, earn bonuses on both, or 
7        earn a bonus for performance on one goal and a penalty 
8        on the other.
9            (C) No bonus shall be earned if a utility does not 
10        achieve greater than 100% of an approved goal. The 
11        maximum bonus for a goal shall be earned if the utility 
12        achieves 125% of the unmodified goal. For a utility 
13        that serves less than 3,000,000 retail customers but 
14        more than 500,000 retail customers in the State, the 
15        bonus earned for achieving more than 100% of an 
16        approved goal but less than 125% of the unmodified 
17        goal shall be linearly interpolated. For a utility 
18        with more than 3,000,000 retail customers, the maximum 
19        bonus for a goal shall be earned if the utility 
20        achieves 125% of the unmodified goal. For a utility 
21        with more than 3,000,000 retail customers, the bonus 
22        earned for achieving more than 100% of an approved 
23        goal but less than 125% of the unmodified goal shall be 
24        linearly interpolated.
25            (D) For utilities with greater than 3,000,000 
26        retail customers, the return on equity shall be 
 
 
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1        unmodified due to performance on an individual goal 
2        only if the utility achieves exactly 100% of the goal. 
3        For utilities with more than 500,000 but fewer than 
4        3,000,000 retail customers, the return on equity shall 
5        be unmodified for achieving between 85% and 100% of 
6        the goal.
7            (E) Penalties may be earned for falling short of 
8        goals, with the magnitude of any penalty being a 
9        function of both the size of the utility and whether 
10        goals established in subsection (b-16) are modified by 
11        the Commission under paragraph (4) of subsection (f) 
12        of this Section, as follows:
13                (i) If the savings goals specified in 
14            subsection (b-16) of this Section are unmodified, 
15            a utility with more than 3,000,000 retail 
16            customers shall earn the maximum penalty allocated 
17            to a goal for achieving 75% or less of the goal. 
18            The penalty for achieving greater than 75% but 
19            less than 100% of the goal shall be linearly 
20            interpolated.
21                (ii) If the savings goals specified in 
22            subsection (b-16) of this Section are unmodified, 
23            a utility with more than 500,000 but fewer than 
24            3,000,000 retail customers shall earn the maximum 
25            penalty allocated to a goal for achieving at least 
26            33.3 percentage points less than the bottom end of 
 
 
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1            the deadband specified in subparagraph (D) of this 
2            paragraph (8.5). The penalty for achieving less 
3            than the bottom end of the deadband and greater 
4            than 33.3 percentage points less than the bottom 
5            end of the deadband shall be linearly 
6            interpolated.
7                (iii) If either the energy or peak demand 
8            savings goals specified in subsection (b-16) are 
9            reduced under paragraph (3) or (4) of subsection 
10            (f) of this Section, the maximum penalty allocated 
11            to a goal shall be earned if the utility achieves 
12            80% or less of the modified goal. The penalty for 
13            achieving more than 80% but less than 100% of a 
14            modified goal shall be linearly interpolated.    
15        (9) The utility shall submit the energy savings data 
16    to the independent evaluator no later than 30 days after 
17    the close of the plan year. The independent evaluator 
18    shall determine the cumulative persisting annual savings 
19    and annual incremental savings for a given plan year, as 
20    well as an estimate of job impacts and other macroeconomic 
21    impacts of the efficiency programs for that year, no later 
22    than 120 days after the close of the plan year. The utility 
23    shall submit an informational filing to the Commission no 
24    later than 160 days after the close of the plan year that 
25    attaches the independent evaluator's final report 
26    identifying the cumulative persisting annual savings for 
 
 
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1    the year and calculates, under paragraph (7) or (8) of 
2    this subsection (g), as applicable, any resulting change 
3    to the utility's return on equity component of the 
4    weighted average cost of capital applicable to the next 
5    plan year beginning with the January monthly billing 
6    period and extending through the December monthly billing 
7    period. However, if the utility recovers the costs 
8    incurred under this Section under paragraphs (2) and (3) 
9    of subsection (d) of this Section, then the utility shall 
10    not be required to submit such informational filing, and 
11    shall instead submit the information that would otherwise 
12    be included in the informational filing as part of its 
13    filing under paragraph (3) of such subsection (d) that is 
14    due on or before June 1 of each year.
15        For those utilities that must submit the informational 
16    filing, the Commission may, on its own motion or by 
17    petition, initiate an investigation of such filing, 
18    provided, however, that the utility's proposed return on 
19    equity calculation shall be deemed the final, approved 
20    calculation on December 15 of the year in which it is filed 
21    unless the Commission enters an order on or before 
22    December 15, after notice and hearing, that modifies such 
23    calculation consistent with this Section.
24        The adjustments to the return on equity component 
25    described in paragraphs (7) and (8) of this subsection (g) 
26    shall be applied as described in such paragraphs through a 
 
 
10400SB0025ham004- 590 -LRB104 16098 AAS 29398 a

1    separate tariff mechanism, which shall be filed by the 
2    utility under subsections (f) and (g) of this Section. 
3        (9.5) The utility must demonstrate how it will ensure 
4    that program implementation contractors and energy 
5    efficiency installation vendors will promote workforce 
6    equity and quality jobs. For all construction, 
7    installation, or other related services procured under 
8    this Section, an electric utility must:
9            (A) award a bid preference of 2% to a contractor if 
10        the contractor certifies under oath that the 
11        contractor's primary place of business is located 
12        within the utility's service area; and
13            (B) award a bid preference of 2% to a contractor if 
14        the contractor certifies under oath that at least 85% 
15        of the workforce to be utilized for such construction, 
16        installation, or other related services reside in the 
17        utility's service area.    
18        (9.6) Utilities shall collect data necessary to ensure 
19    compliance with paragraph (9.5) no less than quarterly and 
20    shall communicate progress toward compliance with 
21    paragraph (9.5) to program implementation contractors and 
22    energy efficiency installation vendors no less than 
23    quarterly. Utilities shall work with relevant vendors, 
24    providing education, training, and other resources needed 
25    to ensure compliance and, where necessary, adjusting or 
26    terminating work with vendors that cannot assist with 
 
 
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1    compliance.
2        (10) Utilities required to implement efficiency 
3    programs under subsections (b-5), and (b-10), and (b-16)    
4    shall report annually to the Illinois Commerce Commission 
5    and the General Assembly on how hiring, contracting, job 
6    training, and other practices related to its energy 
7    efficiency programs enhance the diversity of vendors 
8    working on such programs. These reports must include data 
9    on vendor and employee diversity, including data on the 
10    implementation of paragraphs (9.5) and (9.6) and the 
11    proportion of total program dollars awarded to firms that 
12    meet the criteria of subparagraphs (A) and (B) of 
13    paragraph (9.5). If the utility is not meeting the 
14    requirements of paragraphs (9.5) and (9.6), the utility 
15    shall submit a plan to adjust their activities so that 
16    they meet the requirements of paragraphs (9.5) and (9.6) 
17    within the following year.
18    (h) No more than 4% of energy efficiency and 
19demand-response program revenue may be allocated for research, 
20development, or pilot deployment of new equipment or measures. 
21Electric utilities shall work with interested stakeholders to 
22formulate a plan for how these funds should be spent, 
23incorporate statewide approaches for these allocations, and 
24file a 4-year plan that demonstrates that collaboration. If a 
25utility files a request for modified annual energy savings 
26goals with the Commission, then a utility shall forgo spending 
 
 
10400SB0025ham004- 592 -LRB104 16098 AAS 29398 a

1portfolio dollars on research and development proposals. 
2    (i) When practicable, electric utilities shall incorporate 
3advanced metering infrastructure data into the planning, 
4implementation, and evaluation of energy efficiency measures 
5and programs, subject to the data privacy and confidentiality 
6protections of applicable law.
7    (j) The independent evaluator shall follow the guidelines 
8and use the savings set forth in Commission-approved energy 
9efficiency policy manuals and technical reference manuals, as 
10each may be updated from time to time. Until such time as 
11measure life values for energy efficiency measures implemented 
12for low-income households under subsection (c) of this Section 
13are incorporated into such Commission-approved manuals, the 
14low-income measures shall have the same measure life values 
15that are established for same measures implemented in 
16households that are not low-income households.
17    (k) Notwithstanding any provision of law to the contrary, 
18an electric utility subject to the requirements of this 
19Section may file a tariff cancelling an automatic adjustment 
20clause tariff in effect under this Section or Section 8-103, 
21which shall take effect no later than one business day after 
22the date such tariff is filed. Thereafter, the utility shall 
23be authorized to defer and recover its expenditures incurred 
24under this Section through a new tariff authorized under 
25subsection (d) of this Section or in the utility's next rate 
26case under Article IX or Section 16-108.5 of this Act, with 
 
 
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1interest at an annual rate equal to the utility's weighted 
2average cost of capital as approved by the Commission in such 
3case. If the utility elects to file a new tariff under 
4subsection (d) of this Section, the utility may file the 
5tariff within 10 days after June 1, 2017 (the effective date of 
6Public Act 99-906), and the cost inputs to such tariff shall be 
7based on the projected costs to be incurred by the utility 
8during the calendar year in which the new tariff is filed and 
9that were not recovered under the tariff that was cancelled as 
10provided for in this subsection. Such costs shall include 
11those incurred or to be incurred by the utility under its 
12multi-year plan approved under subsections (f) and (g) of this 
13Section, including, but not limited to, projected capital 
14investment costs and projected regulatory asset balances with 
15correspondingly updated depreciation and amortization reserves 
16and expense. The Commission shall, after notice and hearing, 
17approve, or approve with modification, such tariff and cost 
18inputs no later than 75 days after the utility filed the 
19tariff, provided that such approval, or approval with 
20modification, shall be consistent with the provisions of this 
21Section to the extent they do not conflict with this 
22subsection (k). The tariff approved by the Commission shall 
23take effect no later than 5 days after the Commission enters 
24its order approving the tariff.
25    No later than 60 days after the effective date of the 
26tariff cancelling the utility's automatic adjustment clause 
 
 
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1tariff, the utility shall file a reconciliation that 
2reconciles the moneys collected under its automatic adjustment 
3clause tariff with the costs incurred during the period 
4beginning June 1, 2016 and ending on the date that the electric 
5utility's automatic adjustment clause tariff was cancelled. In 
6the event the reconciliation reflects an under-collection, the 
7utility shall recover the costs as specified in this 
8subsection (k). If the reconciliation reflects an 
9over-collection, the utility shall apply the amount of such 
10over-collection as a one-time credit to retail customers' 
11bills.
12    (l) For the calendar years covered by a multi-year plan 
13commencing after December 31, 2017, subsections (a) through 
14(j) of this Section do not apply to eligible large private 
15energy customers that have chosen to opt out of multi-year 
16plans consistent with this subsection (1).
17        (1) For purposes of this subsection (l), "eligible 
18    large private energy customer" means any retail customers, 
19    except for federal, State, municipal, and other public 
20    customers, of an electric utility that serves more than 
21    3,000,000 retail customers, except for federal, State, 
22    municipal and other public customers, in the State and 
23    whose total highest 30 minute demand was more than 10,000 
24    kilowatts, or any retail customers of an electric utility 
25    that serves less than 3,000,000 retail customers but more 
26    than 500,000 retail customers in the State and whose total 
 
 
10400SB0025ham004- 595 -LRB104 16098 AAS 29398 a

1    highest 15 minute demand was more than 10,000 kilowatts. 
2    For purposes of this subsection (l), "retail customer" has 
3    the meaning set forth in Section 16-102 of this Act. 
4    However, for a business entity with multiple sites located 
5    in the State, where at least one of those sites qualifies 
6    as an eligible large private energy customer, then any of 
7    that business entity's sites, properly identified on a 
8    form for notice, shall be considered eligible large 
9    private energy customers for the purposes of this 
10    subsection (l). A determination of whether this subsection 
11    is applicable to a customer shall be made for each 
12    multi-year plan beginning after December 31, 2017. The 
13    criteria for determining whether this subsection (l) is 
14    applicable to a retail customer shall be based on the 12 
15    consecutive billing periods prior to the start of the 
16    first year of each such multi-year plan.
17        (2) Within 45 days after September 15, 2021 (the 
18    effective date of Public Act 102-662), the Commission 
19    shall prescribe the form for notice required for opting 
20    out of energy efficiency programs. The notice must be 
21    submitted to the retail electric utility 12 months before 
22    the next energy efficiency planning cycle. However, within 
23    120 days after the Commission's initial issuance of the 
24    form for notice, eligible large private energy customers 
25    may submit a form for notice to an electric utility. The 
26    form for notice for opting out of energy efficiency 
 
 
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1    programs shall include all of the following:
2            (A) a statement indicating that the customer has 
3        elected to opt out;
4            (B) the account numbers for the customer accounts 
5        to which the opt out shall apply;
6            (C) the mailing address associated with the 
7        customer accounts identified under subparagraph (B);
8            (D) an American Society of Heating, Refrigerating, 
9        and Air-Conditioning Engineers (ASHRAE) level 2 or 
10        higher audit report conducted by an independent 
11        third-party expert identifying cost-effective energy 
12        efficiency project opportunities that could be 
13        invested in over the next 10 years. A retail customer 
14        with specialized processes may utilize a self-audit 
15        process in lieu of the ASHRAE audit;
16            (E) a description of the customer's plans to 
17        reallocate the funds toward internal energy efficiency 
18        efforts identified in the subparagraph (D) report, 
19        including, but not limited to: (i) strategic energy 
20        management or other programs, including descriptions 
21        of targeted buildings, equipment and operations; (ii) 
22        eligible energy efficiency measures; and (iii) 
23        expected energy savings, itemized by technology. If 
24        the subparagraph (D) audit report identifies that the 
25        customer currently utilizes the best available energy 
26        efficient technology, equipment, programs, and 
 
 
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1        operations, the customer may provide a statement that 
2        more efficient technology, equipment, programs, and 
3        operations are not reasonably available as a means of 
4        satisfying this subparagraph (E); and
5            (F) the effective date of the opt out, which will 
6        be the next January 1 following notice of the opt out.
7        (3) Upon receipt of a properly and timely noticed 
8    request for opt out submitted by an eligible large private 
9    energy customer, the retail electric utility shall grant 
10    the request, file the request with the Commission and, 
11    beginning January 1 of the following year, the opted out 
12    customer shall no longer be assessed the costs of the plan 
13    and shall be prohibited from participating in that 4-year 
14    plan cycle to give the retail utility the certainty to 
15    design program plan proposals.
16        (4) Upon a customer's election to opt out under 
17    paragraphs (1) and (2) of this subsection (l) and 
18    commencing on the effective date of said opt out, the 
19    account properly identified in the customer's notice under 
20    paragraph (2) shall not be subject to any cost recovery 
21    and shall not be eligible to participate in, or directly 
22    benefit from, compliance with energy efficiency cumulative 
23    persisting savings requirements under subsections (a) 
24    through (j).
25        (5) A utility's cumulative persisting annual savings 
26    targets will exclude any opted out load.
 
 
10400SB0025ham004- 598 -LRB104 16098 AAS 29398 a

1        (6) The request to opt out is only valid for the 
2    requested plan cycle. An eligible large private energy 
3    customer must also request to opt out for future energy 
4    plan cycles, otherwise the customer will be included in 
5    the future energy plan cycle. 
6    (m) Notwithstanding the requirements of this Section, as 
7part of a proceeding to approve a multi-year plan under 
8subsections (f) and (g) of this Section if the multi-year plan 
9has been designed to maximize savings, but does not meet the 
10cost cap limitations of this Section, the Commission shall 
11reduce the amount of energy efficiency measures implemented 
12for any single year, and whose costs are recovered under 
13subsection (d) of this Section, by an amount necessary to 
14limit the estimated average net increase due to the cost of the 
15measures to no more than
16        (1) 3.5% for each of the 4 years beginning January 1, 
17    2018,
18        (2) (blank),
19        (3) 4% for each of the 4 years beginning January 1, 
20    2022,
21        (3.5) 4.25% for 2026,    
22        (4) 4.25% for electric utilities that serve more than 
23    3,000,000 retail customers in the State, and 4.21% for 
24    2027, 5.25% for 2028, and 6.06% for 2029 for electric 
25    utilities with less than 3,000,000 retail customers but 
26    more than 500,000 retail customers in the State, for the 3    
 
 
10400SB0025ham004- 599 -LRB104 16098 AAS 29398 a

1    4 years beginning January 1, 2027 2026, and
2        (5) the percentage specified in paragraph (4) 
3    applicable to 2029 4.25% plus an increase sufficient to 
4    account for the rate of inflation between January 1, 2027    
5    2026 and January 1 of the first year of each subsequent 
6    4-year plan cycle, 
7of the average amount paid per kilowatthour by residential 
8eligible retail customers during calendar year 2015 for plans 
9in effect through 2026 and during calendar year 2023 for plans 
10commencing in 2027 and thereafter. An electric utility may 
11plan to spend up to 10% more in any year during an applicable 
12multi-year plan period, including any transition period 
13authorized under paragraph (2.5) of subsection (f), to 
14cost-effectively achieve additional savings so long as the 
15average over the applicable multi-year plan period, which 
16shall include any transition period, does not exceed the 
17percentages defined in items (1) through (5). To determine the 
18total amount that may be spent by an electric utility in any 
19single year, the applicable percentage of the average amount 
20paid per kilowatthour shall be multiplied by the total amount 
21of energy delivered by such electric utility in the calendar 
22year 2015 for plans in effect through 2026 and during calendar 
23year 2023 for plans commencing in 2027 and thereafter, 
24adjusted to reflect the proportion of the utility's load 
25attributable to customers that have opted out of subsections 
26(a) through (j) of this Section under subsection (l) of this 
 
 
10400SB0025ham004- 600 -LRB104 16098 AAS 29398 a

1Section. For purposes of this subsection (m), the amount paid 
2per kilowatthour includes, without limitation, estimated 
3amounts paid for supply, transmission, distribution, 
4surcharges, and add-on taxes. For purposes of this Section, 
5"eligible retail customers" shall have the meaning set forth 
6in Section 16-111.5 of this Act. Once the Commission has 
7approved a plan under subsections (f) and (g) of this Section, 
8no subsequent rate impact determinations shall be made.
9    (n) A utility shall take advantage of the efficiencies 
10available through existing Illinois Home Weatherization 
11Assistance Program infrastructure and services, such as 
12enrollment, marketing, quality assurance and implementation, 
13which can reduce the need for similar services at a lower cost 
14than utility-only programs, subject to capacity constraints at 
15community action agencies, for both single-family and 
16multifamily weatherization services, to the extent Illinois 
17Home Weatherization Assistance Program community action 
18agencies provide multifamily services. A utility's plan shall 
19demonstrate that in formulating annual weatherization budgets, 
20it has sought input and coordination with community action 
21agencies regarding agencies' capacity to expand and maximize 
22Illinois Home Weatherization Assistance Program delivery using 
23the ratepayer dollars collected under this Section. 
24(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23; 
25103-613, eff. 7-1-24.)
 
 
 
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1    (220 ILCS 5/8-104)
2    Sec. 8-104. Natural gas energy efficiency programs.
3    (a) It is the policy of the State that natural gas 
4utilities and the Department of Commerce and Economic 
5Opportunity are required to use cost-effective energy 
6efficiency to reduce direct and indirect costs to consumers. 
7It serves the public interest to allow natural gas utilities 
8to recover costs for reasonably and prudently incurred 
9expenses for cost-effective energy efficiency measures.
10    (b) For purposes of this Section, "energy efficiency" 
11means measures that reduce the amount of energy required to 
12achieve a given end use. "Energy efficiency" also includes 
13measures that reduce the total Btus of electricity and natural 
14gas needed to meet the end use or uses. "Cost-effective" means 
15that the measures satisfy the total resource cost test which, 
16for purposes of this Section, means a standard that is met if, 
17for an investment in energy efficiency, the benefit-cost ratio 
18is greater than one. The benefit-cost ratio is the ratio of the 
19net present value of the total benefits of the measures to the 
20net present value of the total costs as calculated over the 
21lifetime of the measures. The total resource cost test 
22compares the sum of avoided natural gas utility costs, 
23representing the benefits that accrue to the system and the 
24participant in the delivery of those efficiency measures, as 
25well as other quantifiable societal benefits, including 
26avoided electric utility costs, to the sum of all incremental 
 
 
10400SB0025ham004- 602 -LRB104 16098 AAS 29398 a

1costs of end use measures (including both utility and 
2participant contributions), plus costs to administer, deliver, 
3and evaluate each demand-side measure, to quantify the net 
4savings obtained by substituting demand-side measures for 
5supply resources. In calculating avoided costs, reasonable 
6estimates shall be included for financial costs likely to be 
7imposed by future regulation of emissions of greenhouse gases. 
8The low-income programs described in item (4) of subsection 
9(f) of this Section shall not be required to meet the total 
10resource cost test.
11    (c) Natural gas utilities shall implement cost-effective 
12energy efficiency measures to meet at least the following 
13natural gas savings requirements, which shall be based upon 
14the total amount of gas delivered to retail customers, other 
15than the customers described in subsection (m) of this 
16Section, during calendar year 2009 multiplied by the 
17applicable percentage. Natural gas utilities may comply with 
18this Section by meeting the annual incremental savings goal in 
19the applicable year or by showing that total cumulative annual 
20savings within a multi-year planning period associated with 
21measures implemented after May 31, 2011 were equal to the sum 
22of each annual incremental savings requirement from the first 
23day of the multi-year planning period through the last day of 
24the multi-year planning period:
25        (1) 0.2% by May 31, 2012;
26        (2) an additional 0.4% by May 31, 2013, increasing 
 
 
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1    total savings to .6%;
2        (3) an additional 0.6% by May 31, 2014, increasing 
3    total savings to 1.2%;
4        (4) an additional 0.8% by May 31, 2015, increasing 
5    total savings to 2.0%;
6        (5) an additional 1% by May 31, 2016, increasing total 
7    savings to 3.0%;
8        (6) an additional 1.2% by May 31, 2017, increasing 
9    total savings to 4.2%;
10        (7) an additional 1.4% in the year commencing January 
11    1, 2018;
12        (8) an additional 1.5% in the year commencing January 
13    1, 2019; and
14        (9) an additional 1.5% in each 12-month period 
15    thereafter.
16    (d) Notwithstanding the requirements of subsection (c) of 
17this Section, a natural gas utility shall limit the amount of 
18energy efficiency implemented in any multi-year reporting 
19period established by subsection (f) of Section 8-104 of this 
20Act, by an amount necessary to limit the estimated average 
21increase in the amounts paid by retail customers in connection 
22with natural gas service to no more than 2% in the applicable 
23multi-year reporting period. The energy savings requirements 
24in subsection (c) of this Section may be reduced by the 
25Commission for the subject plan, if the utility demonstrates 
26by substantial evidence that it is highly unlikely that the 
 
 
10400SB0025ham004- 604 -LRB104 16098 AAS 29398 a

1requirements could be achieved without exceeding the 
2applicable spending limits in any multi-year reporting period. 
3No later than September 1, 2013, the Commission shall review 
4the limitation on the amount of energy efficiency measures 
5implemented pursuant to this Section and report to the General 
6Assembly, in the report required by subsection (k) of this 
7Section, its findings as to whether that limitation unduly 
8constrains the procurement of energy efficiency measures.
9    (e) The provisions of this subsection (e) apply to those 
10multi-year plans that commence prior to January 1, 2018. The 
11utility shall utilize 75% of the available funding associated 
12with energy efficiency programs approved by the Commission, 
13and may outsource various aspects of program development and 
14implementation. The remaining 25% of available funding shall 
15be used by the Department of Commerce and Economic Opportunity 
16to implement energy efficiency measures that achieve no less 
17than 20% of the requirements of subsection (c) of this 
18Section. Such measures shall be designed in conjunction with 
19the utility and approved by the Commission. The Department may 
20outsource development and implementation of energy efficiency 
21measures. A minimum of 10% of the entire portfolio of 
22cost-effective energy efficiency measures shall be procured 
23from local government, municipal corporations, school 
24districts, public institutions of higher education, and 
25community college districts. Five percent of the entire 
26portfolio of cost-effective energy efficiency measures may be 
 
 
10400SB0025ham004- 605 -LRB104 16098 AAS 29398 a

1granted to local government and municipal corporations for 
2market transformation initiatives. The Department shall 
3coordinate the implementation of these measures and shall 
4integrate delivery of natural gas efficiency programs with 
5electric efficiency programs delivered pursuant to Section 
68-103 of this Act, unless the Department can show that 
7integration is not feasible.
8    The apportionment of the dollars to cover the costs to 
9implement the Department's share of the portfolio of energy 
10efficiency measures shall be made to the Department once the 
11Department has executed rebate agreements, grants, or 
12contracts for energy efficiency measures and provided 
13supporting documentation for those rebate agreements, grants, 
14and contracts to the utility. The Department is authorized to 
15adopt any rules necessary and prescribe procedures in order to 
16ensure compliance by applicants in carrying out the purposes 
17of rebate agreements for energy efficiency measures 
18implemented by the Department made under this Section. 
19    The details of the measures implemented by the Department 
20shall be submitted by the Department to the Commission in 
21connection with the utility's filing regarding the energy 
22efficiency measures that the utility implements.
23    The portfolio of measures, administered by both the 
24utilities and the Department, shall, in combination, be 
25designed to achieve the annual energy savings requirements set 
26forth in subsection (c) of this Section, as modified by 
 
 
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1subsection (d) of this Section.
2    The utility and the Department shall agree upon a 
3reasonable portfolio of measures and determine the measurable 
4corresponding percentage of the savings goals associated with 
5measures implemented by the Department.
6    No utility shall be assessed a penalty under subsection 
7(f) of this Section for failure to make a timely filing if that 
8failure is the result of a lack of agreement with the 
9Department with respect to the allocation of responsibilities 
10or related costs or target assignments. In that case, the 
11Department and the utility shall file their respective plans 
12with the Commission and the Commission shall determine an 
13appropriate division of measures and programs that meets the 
14requirements of this Section.
15    (e-5) The provisions of this subsection (e-5) shall be 
16applicable to those multi-year plans that commence after 
17December 31, 2017. Natural gas utilities shall be responsible 
18for overseeing the design, development, and filing of their 
19efficiency plans with the Commission and may outsource 
20development and implementation of energy efficiency measures. 
21A minimum of 10% of the entire portfolio of cost-effective 
22energy efficiency measures shall be procured from local 
23government, municipal corporations, school districts, public 
24institutions of higher education, and community college 
25districts. Five percent of the entire portfolio of 
26cost-effective energy efficiency measures may be granted to 
 
 
10400SB0025ham004- 607 -LRB104 16098 AAS 29398 a

1local government and municipal corporations for market 
2transformation initiatives.
3    Through calendar year 2026, the The utilities shall also 
4present a portfolio of energy efficiency measures 
5proportionate to the share of total annual utility revenues in 
6Illinois from households at or below 150% of the poverty 
7level. Such programs shall be targeted to households with 
8incomes at or below 80% of area median income. 
9    (e-7) Beginning January 1, 2027, the following 
10requirements shall apply to efficiency programs that are 
11targeted to low-income households:    
12        (1) For gas utilities with greater than 300,000 
13    customers, the portion of the entire budget for efficiency 
14    programs that is spent on efficiency measures for 
15    low-income households shall be no less than 25% or 5 
16    percentage points more than the proportion of total annual 
17    gas sales to non-opt-out retail customers that are 
18    consumed by low-income households, whichever is greater. 
19    For gas utilities with 300,000 or fewer customers, the 
20    portion of the entire budget for efficiency programs that 
21    is spent on efficiency measures for low-income households 
22    shall be no less than 15% or 5 percentage points more than 
23    the proportion of total annual gas sales to non-opt-out 
24    retail customers that are consumed by low-income 
25    households, whichever is greater.    
26        (2) The portion of spending on efficiency measures 
 
 
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1    targeted to low-income households that shall be delivered 
2    through whole building weatherization programs that 
3    comprehensively address building envelope efficiency 
4    upgrade opportunities and other efficiency measures shall 
5    be at least 80%.    
6        (3) Utilities shall invest in health and safety 
7    measures appropriate and necessary for comprehensively 
8    weatherizing the single-family and multi-family buildings 
9    of low-income households, with up to 15% of 
10    income-qualified program spending made available for such 
11    purposes. All such health and safety spending shall count 
12    toward the requirement in paragraph (2) of this subsection 
13    (e-7) to spend low-income funds on heat load reducing 
14    measures.    
15        (4) Utilities shall leverage existing State and 
16    federal low-income weatherization programs and delivery 
17    capacity to the extent practicable. Utilities shall also 
18    prioritize contracting with organizations, government 
19    agencies, and businesses with a track record of delivering 
20    weatherization services in low-income communities in this 
21    State to deliver any low-income programs that are not 
22    integrated with State and federal low-income 
23    weatherization programs.
24    For the purposes of this subsection (e-7), "low-income 
25households" means households with incomes at or below 80% of 
26the area median income.    
 
 
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1    (e-10) A utility providing approved energy efficiency 
2measures in this State shall be permitted to recover costs of 
3those measures through an automatic adjustment clause tariff 
4filed with and approved by the Commission. The tariff shall be 
5established outside the context of a general rate case and 
6shall be applicable to the utility's customers other than the 
7customers described in subsection (m) of this Section. Each 
8year the Commission shall initiate a review to reconcile any 
9amounts collected with the actual costs and to determine the 
10required adjustment to the annual tariff factor to match 
11annual expenditures.
12    (e-15) For those multi-year plans that commence prior to 
13January 1, 2018, each utility shall include, in its recovery 
14of costs, the costs estimated for both the utility's and the 
15Department's implementation of energy efficiency measures. 
16Costs collected by the utility for measures implemented by the 
17Department shall be submitted to the Department pursuant to 
18Section 605-323 of the Civil Administrative Code of Illinois, 
19shall be deposited into the Energy Efficiency Portfolio 
20Standards Fund, and shall be used by the Department solely for 
21the purpose of implementing these measures. A utility shall 
22not be required to advance any moneys to the Department but 
23only to forward such funds as it has collected. The Department 
24shall report to the Commission on an annual basis regarding 
25the costs actually incurred by the Department in the 
26implementation of the measures. Any changes to the costs of 
 
 
10400SB0025ham004- 610 -LRB104 16098 AAS 29398 a

1energy efficiency measures as a result of plan modifications 
2shall be appropriately reflected in amounts recovered by the 
3utility and turned over to the Department.
4    (e-20) The provisions of this Section shall be applicable 
5to multi-year plans that commence after the effective date of 
6this amendatory Act of the 104th General Assembly and are 
7submitted by single fuel service utilities on or before the 
8effective date of this amendatory Act of the 104th General 
9Assembly. A natural gas utility may propose, as part of its 
10submission of a multi-year plan, to increase the amount of 
11energy efficiency implemented in any multi-year planning 
12period above the level that can be achieved under the spending 
13cap set forth in subsection (d) of this Section. The first plan 
14to increase energy efficiency may be submitted as an amendment 
15to the utility's plan for calendar years 2027 through 2029, 
16but any amended plans must be filed with the Commission by 
17March 1, 2026 or the effective date of this amendatory Act of 
18the 104th General Assembly, whichever is later. In addition to 
19the policy goals established in subsection (f), the Commission 
20shall consider, in determining the appropriateness of a 
21proposal, whether the multi-year plan at a minimum:    
22        (1) identifies a cost-effective portfolio of measures 
23    and specifies the natural gas savings that are reasonably 
24    likely to be achieved by the utility;
25        (2) demonstrates that the plan or modified plan, at a 
26    minimum, will result in a portfolio of energy efficiency 
 
 
10400SB0025ham004- 611 -LRB104 16098 AAS 29398 a

1    measures that will provide more natural gas savings than 
2    would have been achieved in a plan subject to subsection 
3    (c);
4        (3) demonstrates that the plan reflects efforts to 
5    coordinate delivery of electric utility efficiency 
6    programs where such coordination can reduce costs, 
7    increase effectiveness of outreach to customers, and 
8    increase savings. A gas utility may count electricity 
9    savings toward its gas efficiency savings goals subject to 
10    the following limitations:
11            (A) only electricity savings produced as a result 
12        of the installation of a gas efficiency measure, such 
13        as reductions in electricity consumption by gas 
14        furnace fans and electric air conditioners that 
15        results from the installation of insulation measures 
16        that reduce gas used for space heating, may be 
17        counted;
18            (B) such electricity savings may only be counted 
19        when they are generated in service territories not 
20        served by electric utilities subject to Section 
21        8-103B;
22            (C) no more than 5% of the total savings claimed 
23        toward a gas utility's savings goal may be from such 
24        electricity savings. For the purposes of this Section, 
25        a kilowatt-hour of savings is equal to 0.03412 gas 
26        therms;
 
 
10400SB0025ham004- 612 -LRB104 16098 AAS 29398 a

1        (4) demonstrates whether an increase in funding is 
2    necessary to meet the proposed increase in the amount of 
3    energy efficiency;
4        (5) prioritizes income-qualified measures and 
5    weatherization measures; and
6        (6) demonstrates that the multi-year plan strikes a 
7    reasonable balance between the goals of the following:
8            (A) increasing cost-effective efficiency savings 
9        and related greenhouse gas emission reductions;
10            (B) reducing overall gas system costs, recognizing 
11        that efficiency investments reduce usage and, in turn, 
12        the potential need for system investments over the 
13        long-term;
14            (C) increasing energy affordability, especially 
15        for low-income customers;
16            (D) within the residential sector, prioritizing 
17        investment in weatherization and other measures that 
18        reduce heating loads over gas equipment measures; and
19            (E) providing a diverse cross-section of 
20        opportunities for customers of all rate classes to 
21        participate in efficiency programs.
22    As part of its order approving the plan or modified plan, 
23the Commission is authorized to:
24        (1) adjust the limitation on the amount of energy 
25    efficiency measures implemented pursuant to subsection (d) 
26    to the extent necessary to meet the increase in the amount 
 
 
10400SB0025ham004- 613 -LRB104 16098 AAS 29398 a

1    of energy efficiency approved by the Commission pursuant 
2    to this subsection (e-20); and
3        (2) adopt an incentive mechanism for the utility to 
4    meet or exceed the goals associated with its proposed 
5    multi-year plan if the utility meets or exceeds the 
6    following minimum requirements:
7            (A) the utility proposes a plan budget over the 
8        applicable multi-year period that is equal to or 
9        greater than 5% of the amounts paid by non-opt-out 
10        retail customers in connection with natural gas 
11        service in the applicable multi-year period.
12            (B) for efficiency program years 2027 through 
13        2029, the utility achieves average incremental annual 
14        savings of at least 0.7% of total average annual gas 
15        sales to non-opt-out retail customers over the years 
16        2023 through 2025. For multi-year efficiency program 
17        plans beginning after 2029, achieving average 
18        incremental annual savings of at least 0.8% of total 
19        average annual gas sales to non-opt-out retail 
20        customers during the 3-year period ending 2 years 
21        prior to the first year of the plan. In all multi-year 
22        periods, the minimum incremental annual savings 
23        requirement shall be reduced by 0.01 percentage points 
24        for every 1 percentage point increase in low-income or 
25        moderate-income spending above the minimum levels 
26        required by subsection (e-5). In no event shall the 
 
 
10400SB0025ham004- 614 -LRB104 16098 AAS 29398 a

1        minimum incremental annual savings requirement be 
2        reduced by more than 0.10 percentage points even if 
3        low-income or moderate-income spending is increased by 
4        more than 10 percentage points above the minimum 
5        levels required by subsection (e-5). The Commission 
6        may reduce the magnitude of the minimum savings 
7        requirements under this subparagraph (B) if the 
8        utility can demonstrate that it is not possible to 
9        achieve them with a budget equal to 5% of revenues from 
10        eligible customers while meeting other minimum 
11        requirements. If a utility attempts to demonstrate 
12        that it cannot meet the minimum savings requirements 
13        in this paragraph with a budget equal to 5% of revenues 
14        from eligible customers, and the Commission finds that 
15        the utility has not made a sufficiently compelling 
16        demonstration, the utility may withdraw its plan and 
17        file a revised plan.
18            (C) the utility achieves an average savings life 
19        of at least 12 years. Average savings lives may be 
20        shorter than the average operational lives of measures 
21        if the measures do not produce savings in every year in 
22        which they operate or if the savings that measures 
23        produce decline during their operational lives.
24            (D) the utility spends at least 67% of all 
25        financial incentive dollars on efficiency measures 
26        that (1) reduce the space heating loads of buildings 
 
 
10400SB0025ham004- 615 -LRB104 16098 AAS 29398 a

1        through improvements such as to building envelopes, 
2        ventilation systems, space heating distribution 
3        systems, and space heating system controls; (2) reduce 
4        the water heating loads of buildings such as through 
5        insulation of hot water pipes, recovery and reuse of 
6        heat from waste water and reductions in the amount of 
7        hot water required to meet customer needs; or (3) 
8        reduce the process heat loads of industrial 
9        facilities. No financial incentive spending on 
10        furnaces, boilers, water heaters, and other 
11        gas-consuming equipment may be counted toward this 
12        requirement.
13    For the purposes of this subsection (e-20):
14    "Average savings life" means (i) the savings that will be 
15realized as a result of a utility's efficiency programs over 
16the lives of all efficiency measures divided by (ii) the 
17savings that will be produced in the first year after such 
18measures are installed.    
19    "Moderate-income" means income between 80% of area median 
20income and 300% of the federal poverty limit.    
21    (f) No later than October 1, 2010, each gas utility shall 
22file an energy efficiency plan with the Commission to meet the 
23energy efficiency standards through May 31, 2014. No later 
24than October 1, 2013, each gas utility shall file an energy 
25efficiency plan with the Commission to meet the energy 
26efficiency standards through May 31, 2017. Beginning in 2017 
 
 
10400SB0025ham004- 616 -LRB104 16098 AAS 29398 a

1and every 4 years thereafter, each utility shall file an 
2energy efficiency plan with the Commission to meet the energy 
3efficiency standards for the next applicable 4-year period 
4beginning January 1 of the year following the filing. For 
5those multi-year plans commencing on January 1, 2018, each 
6utility shall file its proposed energy efficiency plan no 
7later than 30 days after the effective date of this amendatory 
8Act of the 99th General Assembly or May 1, 2017, whichever is 
9later. Beginning in 2021 and every 4 years thereafter, each 
10utility shall file its energy efficiency plan no later than 
11March 1. If a utility does not file such a plan on or before 
12the applicable filing deadline for the plan, then it shall 
13face a penalty of $100,000 per day until the plan is filed.
14    Each utility's plan shall set forth the utility's 
15proposals to meet the utility's portion of the energy 
16efficiency standards identified in subsection (c) of this 
17Section, as modified by subsection (d) of this Section, taking 
18into account the unique circumstances of the utility's service 
19territory. For those plans commencing after December 31, 2021, 
20the Commission shall seek public comment on the utility's plan 
21and shall issue an order approving or disapproving each plan 
22within 6 months after its submission. For those plans 
23commencing on January 1, 2018, the Commission shall seek 
24public comment on the utility's plan and shall issue an order 
25approving or disapproving each plan no later than August 31, 
262017, or 105 days after the effective date of this amendatory 
 
 
10400SB0025ham004- 617 -LRB104 16098 AAS 29398 a

1Act of the 99th General Assembly, whichever is later. If the 
2Commission disapproves a plan, the Commission shall, within 30 
3days, describe in detail the reasons for the disapproval and 
4describe a path by which the utility may file a revised draft 
5of the plan to address the Commission's concerns 
6satisfactorily. If the utility does not refile with the 
7Commission within 60 days after the disapproval, the utility 
8shall be subject to penalties at a rate of $100,000 per day 
9until the plan is filed. This process shall continue, and 
10penalties shall accrue, until the utility has successfully 
11filed a portfolio of energy efficiency measures. Penalties 
12shall be deposited into the Energy Efficiency Trust Fund and 
13the cost of any such penalties may not be recovered from 
14ratepayers. In submitting proposed energy efficiency plans and 
15funding levels to meet the savings goals adopted by this Act 
16the utility shall:
17        (1) Demonstrate that its proposed energy efficiency 
18    measures will achieve the requirements that are identified 
19    in subsection (c) of this Section, as modified by 
20    subsection (d) of this Section.
21        (2) Present specific proposals to implement new 
22    building and appliance standards that have been placed 
23    into effect.
24        (3) Present estimates of the total amount paid for gas 
25    service expressed on a per therm basis associated with the 
26    proposed portfolio of measures designed to meet the 
 
 
10400SB0025ham004- 618 -LRB104 16098 AAS 29398 a

1    requirements that are identified in subsection (c) of this 
2    Section, as modified by subsection (d) of this Section.
3        (4) For those multi-year plans that commence prior to 
4    January 1, 2018, coordinate with the Department to present 
5    a portfolio of energy efficiency measures proportionate to 
6    the share of total annual utility revenues in Illinois 
7    from households at or below 150% of the poverty level. 
8    Such programs shall be targeted to households with incomes 
9    at or below 80% of area median income.
10        (5) Demonstrate that its overall portfolio of energy 
11    efficiency measures, not including low-income programs 
12    described in item (4) of this subsection (f) and 
13    subsection (e-5) of this Section, are cost-effective using 
14    the total resource cost test and represent a diverse cross 
15    section of opportunities for customers of all rate classes 
16    to participate in the programs.
17        (6) Demonstrate that a gas utility affiliated with an 
18    electric utility that is required to comply with Section 
19    8-103 or 8-103B of this Act has integrated gas and 
20    electric efficiency measures into a single program that 
21    reduces program or participant costs and appropriately 
22    allocates costs to gas and electric ratepayers. For those 
23    multi-year plans that commence prior to January 1, 2018, 
24    the Department shall integrate all gas and electric 
25    programs it delivers in any such utilities' service 
26    territories, unless the Department can show that 
 
 
10400SB0025ham004- 619 -LRB104 16098 AAS 29398 a

1    integration is not feasible or appropriate.
2        (7) Include a proposed cost recovery tariff mechanism 
3    to fund the proposed energy efficiency measures and to 
4    ensure the recovery of the prudently and reasonably 
5    incurred costs of Commission-approved programs.
6        (8) Provide for quarterly status reports tracking 
7    implementation of and expenditures for the utility's 
8    portfolio of measures and, if applicable, the Department's 
9    portfolio of measures, an annual independent review, and a 
10    full independent evaluation of the multi-year results of 
11    the performance and the cost-effectiveness of the 
12    utility's and, if applicable, Department's portfolios of 
13    measures and broader net program impacts and, to the 
14    extent practical, for adjustment of the measures on a 
15    going forward basis as a result of the evaluations. The 
16    resources dedicated to evaluation shall not exceed 3% of 
17    portfolio resources in any given multi-year period.
18    (g) No more than 3% of expenditures on energy efficiency 
19measures may be allocated for demonstration of breakthrough 
20equipment and devices.
21    (h) Illinois natural gas utilities that are affiliated by 
22virtue of a common parent company may, at the utilities' 
23request, be considered a single natural gas utility for 
24purposes of complying with this Section.
25    (i) If, after 3 years, a gas utility fails to meet the 
26efficiency standard specified in subsection (c) of this 
 
 
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1Section as modified by subsection (d), then it shall make a 
2contribution to the Low-Income Home Energy Assistance Program. 
3The total liability for failure to meet the goal shall be 
4assessed as follows:
5        (1) a large gas utility shall pay $600,000;
6        (2) a medium gas utility shall pay $400,000; and
7        (3) a small gas utility shall pay $200,000.
8    For purposes of this Section, (i) a "large gas utility" is 
9a gas utility that on December 31, 2008, served more than 
101,500,000 gas customers in Illinois; (ii) a "medium gas 
11utility" is a gas utility that on December 31, 2008, served 
12fewer than 1,500,000, but more than 500,000 gas customers in 
13Illinois; and (iii) a "small gas utility" is a gas utility that 
14on December 31, 2008, served fewer than 500,000 and more than 
15100,000 gas customers in Illinois. The costs of this 
16contribution may not be recovered from ratepayers.
17    If a gas utility fails to meet the efficiency standard 
18specified in subsection (c) of this Section, as modified by 
19subsection (d) of this Section, in any 2 consecutive 
20multi-year planning periods, then the responsibility for 
21implementing the utility's energy efficiency measures shall be 
22transferred to an independent program administrator selected 
23by the Commission. Reasonable and prudent costs incurred by 
24the independent program administrator to meet the efficiency 
25standard specified in subsection (c) of this Section, as 
26modified by subsection (d) of this Section, may be recovered 
 
 
10400SB0025ham004- 621 -LRB104 16098 AAS 29398 a

1from the customers of the affected gas utilities, other than 
2customers described in subsection (m) of this Section. The 
3utility shall provide the independent program administrator 
4with all information and assistance necessary to perform the 
5program administrator's duties including but not limited to 
6customer, account, and energy usage data, and shall allow the 
7program administrator to include inserts in customer bills. 
8The utility may recover reasonable costs associated with any 
9such assistance.
10    (j) No utility shall be deemed to have failed to meet the 
11energy efficiency standards to the extent any such failure is 
12due to a failure of the Department.
13    (k) Not later than January 1, 2012, the Commission shall 
14develop and solicit public comment on a plan to foster 
15statewide coordination and consistency between statutorily 
16mandated natural gas and electric energy efficiency programs 
17to reduce program or participant costs or to improve program 
18performance. Not later than September 1, 2013, the Commission 
19shall issue a report to the General Assembly containing its 
20findings and recommendations.
21    (l) This Section does not apply to a gas utility that on 
22January 1, 2009, provided gas service to fewer than 100,000 
23customers in Illinois.
24    (m) Subsections (a) through (k) of this Section do not 
25apply to customers of a natural gas utility that have a North 
26American Industry Classification System code number that is 
 
 
10400SB0025ham004- 622 -LRB104 16098 AAS 29398 a

122111 or any such code number beginning with the digits 31, 32, 
2or 33 and (i) annual usage in the aggregate of 4 million therms 
3or more within the service territory of the affected gas 
4utility or with aggregate usage of 8 million therms or more in 
5this State and complying with the provisions of item (l) of 
6this subsection (m); or (ii) using natural gas as feedstock 
7and meeting the usage requirements described in item (i) of 
8this subsection (m), to the extent such annual feedstock usage 
9is greater than 60% of the customer's total annual usage of 
10natural gas.
11        (1) Customers described in this subsection (m) of this 
12    Section shall apply, on a form approved on or before 
13    October 1, 2009 by the Department, to the Department to be 
14    designated as a self-directing customer ("SDC") or as an 
15    exempt customer using natural gas as a feedstock from 
16    which other products are made, including, but not limited 
17    to, feedstock for a hydrogen plant, on or before the 1st 
18    day of February, 2010. Thereafter, application may be made 
19    not less than 6 months before the filing date of the gas 
20    utility energy efficiency plan described in subsection (f) 
21    of this Section; however, a new customer that commences 
22    taking service from a natural gas utility after February 
23    1, 2010 may apply to become a SDC or exempt customer up to 
24    30 days after beginning service. Customers described in 
25    this subsection (m) that have not already been approved by 
26    the Department may apply to be designated a self-directing 
 
 
10400SB0025ham004- 623 -LRB104 16098 AAS 29398 a

1    customer or exempt customer, on a form approved by the 
2    Department, between September 1, 2013 and September 30, 
3    2013. Customer applications that are approved by the 
4    Department under this amendatory Act of the 98th General 
5    Assembly shall be considered to be a self-directing 
6    customer or exempt customer, as applicable, for the 
7    current 3-year planning period effective December 1, 2013. 
8    Such application shall contain the following:
9            (A) the customer's certification that, at the time 
10        of its application, it qualifies to be a SDC or exempt 
11        customer described in this subsection (m) of this 
12        Section;
13            (B) in the case of a SDC, the customer's 
14        certification that it has established or will 
15        establish by the beginning of the utility's multi-year 
16        planning period commencing subsequent to the 
17        application, and will maintain for accounting 
18        purposes, an energy efficiency reserve account and 
19        that the customer will accrue funds in said account to 
20        be held for the purpose of funding, in whole or in 
21        part, energy efficiency measures of the customer's 
22        choosing, which may include, but are not limited to, 
23        projects involving combined heat and power systems 
24        that use the same energy source both for the 
25        generation of electrical or mechanical power and the 
26        production of steam or another form of useful thermal 
 
 
10400SB0025ham004- 624 -LRB104 16098 AAS 29398 a

1        energy or the use of combustible gas produced from 
2        biomass, or both;
3            (C) in the case of a SDC, the customer's 
4        certification that annual funding levels for the 
5        energy efficiency reserve account will be equal to 2% 
6        of the customer's cost of natural gas, composed of the 
7        customer's commodity cost and the delivery service 
8        charges paid to the gas utility, or $150,000, 
9        whichever is less;
10            (D) in the case of a SDC, the customer's 
11        certification that the required reserve account 
12        balance will be capped at 3 years' worth of accruals 
13        and that the customer may, at its option, make further 
14        deposits to the account to the extent such deposit 
15        would increase the reserve account balance above the 
16        designated cap level;
17            (E) in the case of a SDC, the customer's 
18        certification that by October 1 of each year, 
19        beginning no sooner than October 1, 2012, the customer 
20        will report to the Department information, for the 
21        12-month period ending May 31 of the same year, on all 
22        deposits and reductions, if any, to the reserve 
23        account during the reporting year, and to the extent 
24        deposits to the reserve account in any year are in an 
25        amount less than $150,000, the basis for such reduced 
26        deposits; reserve account balances by month; a 
 
 
10400SB0025ham004- 625 -LRB104 16098 AAS 29398 a

1        description of energy efficiency measures undertaken 
2        by the customer and paid for in whole or in part with 
3        funds from the reserve account; an estimate of the 
4        energy saved, or to be saved, by the measure; and that 
5        the report shall include a verification by an officer 
6        or plant manager of the customer or by a registered 
7        professional engineer or certified energy efficiency 
8        trade professional that the funds withdrawn from the 
9        reserve account were used for the energy efficiency 
10        measures;
11            (F) in the case of an exempt customer, the 
12        customer's certification of the level of gas usage as 
13        feedstock in the customer's operation in a typical 
14        year and that it will provide information establishing 
15        this level, upon request of the Department;
16            (G) in the case of either an exempt customer or a 
17        SDC, the customer's certification that it has provided 
18        the gas utility or utilities serving the customer with 
19        a copy of the application as filed with the 
20        Department;
21            (H) in the case of either an exempt customer or a 
22        SDC, certification of the natural gas utility or 
23        utilities serving the customer in Illinois including 
24        the natural gas utility accounts that are the subject 
25        of the application; and
26            (I) in the case of either an exempt customer or a 
 
 
10400SB0025ham004- 626 -LRB104 16098 AAS 29398 a

1        SDC, a verification signed by a plant manager or an 
2        authorized corporate officer attesting to the 
3        truthfulness and accuracy of the information contained 
4        in the application.
5        (2) The Department shall review the application to 
6    determine that it contains the information described in 
7    provisions (A) through (I) of item (1) of this subsection 
8    (m), as applicable. The review shall be completed within 
9    30 days after the date the application is filed with the 
10    Department. Absent a determination by the Department 
11    within the 30-day period, the applicant shall be 
12    considered to be a SDC or exempt customer, as applicable, 
13    for all subsequent multi-year planning periods, as of the 
14    date of filing the application described in this 
15    subsection (m). If the Department determines that the 
16    application does not contain the applicable information 
17    described in provisions (A) through (I) of item (1) of 
18    this subsection (m), it shall notify the customer, in 
19    writing, of its determination that the application does 
20    not contain the required information and identify the 
21    information that is missing, and the customer shall 
22    provide the missing information within 15 working days 
23    after the date of receipt of the Department's 
24    notification.
25        (3) The Department shall have the right to audit the 
26    information provided in the customer's application and 
 
 
10400SB0025ham004- 627 -LRB104 16098 AAS 29398 a

1    annual reports to ensure continued compliance with the 
2    requirements of this subsection. Based on the audit, if 
3    the Department determines the customer is no longer in 
4    compliance with the requirements of items (A) through (I) 
5    of item (1) of this subsection (m), as applicable, the 
6    Department shall notify the customer in writing of the 
7    noncompliance. The customer shall have 30 days to 
8    establish its compliance, and failing to do so, may have 
9    its status as a SDC or exempt customer revoked by the 
10    Department. The Department shall treat all information 
11    provided by any customer seeking SDC status or exemption 
12    from the provisions of this Section as strictly 
13    confidential.
14        (4) Upon request, or on its own motion, the Commission 
15    may open an investigation, no more than once every 3 years 
16    and not before October 1, 2014, to evaluate the 
17    effectiveness of the self-directing program described in 
18    this subsection (m).
19    Customers described in this subsection (m) that applied to 
20the Department on January 3, 2013, were approved by the 
21Department on February 13, 2013 to be a self-directing 
22customer or exempt customer, and receive natural gas from a 
23utility that provides gas service to at least 500,000 retail 
24customers in Illinois and electric service to at least 
251,000,000 retail customers in Illinois shall be considered to 
26be a self-directing customer or exempt customer, as 
 
 
10400SB0025ham004- 628 -LRB104 16098 AAS 29398 a

1applicable, for the current 3-year planning period effective 
2December 1, 2013. 
3    (m-1) For utilities that file an amended plan for the 
4period covering calendar years 2027 through 2029, and for all 
5utilities for all calendar years covered by a multi-year plan 
6commencing on or after January 1, 2030, subsections (a) 
7through (k) of this Section do not apply to eligible customers 
8of a natural gas utility that have chosen to opt out of 
9multi-year plans.
10        (1) For purposes of this subsection (m-1), "eligible 
11    customer" means any retail customer of a natural gas 
12    utility, except for federal, State, municipal and other 
13    public customers, with a North American Industry 
14    Classification System code number that is 22111 or any 
15    such code number beginning with the digits 31, 32, or 33 
16    and (i) annual usage in the aggregate of 4,000,000 therms 
17    or more within the service territory of the affected gas 
18    utility or with aggregate usage of 8,000,000 therms or 
19    more in this State; or (ii) using natural gas as feedstock 
20    and meeting the usage requirements described in item (i) 
21    of this paragraph (1), to the extent such annual feedstock 
22    usage is greater than 60% of the customer's total annual 
23    usage of natural gas. A determination of whether this 
24    subsection is applicable to a customer shall be made for 
25    each multi-year plan beginning after January 1, 2026. The 
26    criteria for determining whether this subsection is 
 
 
10400SB0025ham004- 629 -LRB104 16098 AAS 29398 a

1    applicable shall be the 12 consecutive billing periods 
2    prior to the start of the first year of each such 
3    multi-year plan.
4        (2) Within 45 days after the effective date of this 
5    amendatory Act of the 104th General Assembly, the 
6    Commission shall prescribe the form for notice required 
7    for opting out of energy efficiency programs. Within 120 
8    days after the Commission's initial issuance of the form 
9    for notice, customers described in paragraph (1) of this 
10    subsection (m-1) may submit completed forms to the natural 
11    gas utility. Thereafter, forms must be submitted to the 
12    natural gas utility not less than 6 months before the 
13    filing date of the gas utility energy efficiency plan 
14    described in subsection (f) of this Section; however, a 
15    new customer that commences taking service from a natural 
16    gas utility after January 1, 2026 may submit a form up to 
17    30 days after beginning service. The form for notice for 
18    opting out of natural gas energy efficiency programs shall 
19    contain the following:
20            (A) a statement indicating that the customer has 
21        elected to opt-out;
22            (B) the account numbers for the customer accounts 
23        to which the opt out shall apply;
24            (C) the mailing address associated with each 
25        customer account identified under subparagraph (B);
26            (D) the customer's certification that, at the time 
 
 
10400SB0025ham004- 630 -LRB104 16098 AAS 29398 a

1        its form was submitted, it qualifies as an eligible 
2        customer, as described in paragraph (1) of this 
3        subsection (m-1);
4            (E) an American Society of Heating, Refrigerating, 
5        and Air Conditioning Engineers (ASHRAE) level 2 or 
6        higher audit report conducted by an independent 
7        third-party expert identifying cost-effective energy 
8        efficiency project opportunities that could be 
9        invested in over the next 10 years. A customer with a 
10        specialized process may use a self-audit process in 
11        lieu of an ASHRAE audit;
12            (F) a description of the customer's plans to 
13        reallocate funds toward internal energy efficiency 
14        efforts identified in the subparagraph (E) report, 
15        including, but not limited to: (i) strategic energy 
16        management or other programs, including descriptions 
17        of targeted buildings, equipment and operations; (ii) 
18        eligible energy efficiency measures; and (iii) 
19        expected energy savings, itemized by technology. If 
20        the subparagraph (E) audit report identifies that the 
21        customer currently utilizes the best available energy 
22        efficient technology, equipment, programs, and 
23        operations, the customer may provide a statement that 
24        more efficient technology, equipment, programs, and 
25        operations are not reasonably available as a means of 
26        satisfying this subparagraph (F); and
 
 
10400SB0025ham004- 631 -LRB104 16098 AAS 29398 a

1            (G) a verification signed by a plant manager or an 
2        authorized corporate officer attesting to the 
3        truthfulness and accuracy of the information contained 
4        in the application.
5        (3) Upon receipt of a properly and timely noticed 
6    request for opt out submitted by an eligible large private 
7    energy customer, the natural gas utility shall grant the 
8    request and file the request with the Commission, and, 
9    beginning January 1 of the first year of the next 
10    multi-year energy efficiency plan cycle, the opted out 
11    customer shall no longer be assessed the costs of the plan 
12    and shall be prohibited from participating in that 
13    multi-year plan cycle to give the natural gas utility the 
14    certainty to design program plan proposals.
15        (4) The request to opt out is only valid for the 
16    requested plan cycle. An eligible large private energy 
17    customer must also request to opt out for future energy 
18    efficiency plan cycles, otherwise the customer will be 
19    included in the future energy efficiency plan cycle.    
20    (n) The applicability of this Section to customers 
21described in subsection (m) of this Section is conditioned on 
22the existence of the SDC program. In no event will any 
23provision of this Section apply to such customers after 
24January 1, 2020.
25    (o) Utilities' 3-year energy efficiency plans approved by 
26the Commission on or before the effective date of this 
 
 
10400SB0025ham004- 632 -LRB104 16098 AAS 29398 a

1amendatory Act of the 99th General Assembly for the period 
2June 1, 2014 through May 31, 2017 shall continue to be in force 
3and effect through December 31, 2017 so that the energy 
4efficiency programs set forth in those plans continue to be 
5offered during the period June 1, 2017 through December 31, 
62017. Each utility is authorized to increase, on a pro rata 
7basis, the energy savings goals and budgets approved in its 
8plan to reflect the additional 7 months of the plan's 
9operation. 
10(Source: P.A. 103-613, eff. 7-1-24.)
 
11    (220 ILCS 5/8-512)
12    Sec. 8-512. Renewable energy access plan.
13    (a) It is the policy of this State to promote 
14cost-effective transmission system development that ensures 
15reliability of the electric transmission system, lowers carbon 
16emissions, minimizes long-term costs for consumers, and 
17supports the electric policy goals of this State. The General 
18Assembly finds that:
19        (1) Transmission planning, primarily for reliability 
20    purposes, but also for economic and public policy reasons 
21    is conducted by regional transmission organizations in 
22    which transmission-owning Illinois utilities and other 
23    stakeholders are members.
24        (2) Order No. 1000 of the Federal Energy Regulatory 
25    Commission requires regional transmission organizations to 
 
 
10400SB0025ham004- 633 -LRB104 16098 AAS 29398 a

1    plan for transmission system needs in light of State 
2    public policies and to accept input from states during the 
3    transmission system planning processes.
4        (3) The State of Illinois does not currently have a 
5    comprehensive power and environmental policy planning 
6    process to identify transmission infrastructure needs that 
7    can serve as a vital input into the regional and 
8    interregional transmission organization planning 
9    processes conducted under Order No. 1000 and other laws 
10    and regulations.
11        (4) This State is an electricity generation and power 
12    transmission hub, and can leverage that position to invest 
13    in infrastructure that enables new and existing Illinois 
14    generators to meet the public policy goals of the State of 
15    Illinois and of interconnected states while 
16    cost-effectively supporting tens of thousands of jobs in 
17    the renewable energy sector in this State.
18        (5) The nation has a need to readily access this 
19    State's low-cost, clean electric power, and this State 
20    also desires access to clean energy resources in other 
21    states to develop and support its low-carbon economy and 
22    keep electricity prices low in Illinois and interconnected 
23    States.
24        (6) Existing transmission infrastructure may constrain 
25    the State's achievement of 100% renewable energy by 2050, 
26    the accelerated adoption of electric vehicles in a just 
 
 
10400SB0025ham004- 634 -LRB104 16098 AAS 29398 a

1    and equitable way, and electrification of additional 
2    sectors of the Illinois economy.
3        (7) Transmission system congestion within this State 
4    and the regional transmission organizations serving this 
5    State limits the ability of this State's existing and new 
6    electric generation facilities that do not emit carbon 
7    dioxide, including renewable energy resources and zero 
8    emission facilities, to serve the public policy goals of 
9    this State and other states, which constrains investment 
10    in this State.
11        (8) Investment in infrastructure to support existing 
12    and new electric generation facilities that do not emit 
13    carbon dioxide, including renewable energy resources and 
14    zero emission facilities, stimulates significant economic 
15    development and job growth in this State, as well as 
16    creates environmental and public health benefits in this 
17    State.
18        (9) Creating a forward-looking plan for this State's 
19    electric transmission infrastructure, as opposed to 
20    relying on case-by-case development and repeated marginal 
21    upgrades, will achieve a lower-cost system for Illinois' 
22    electricity customers. A forward-looking plan can also 
23    help integrate and achieve a comprehensive set of 
24    objectives and multiple state, regional, and national 
25    policy goals.
26        (10) Alternatives to overhead electric transmission 
 
 
10400SB0025ham004- 635 -LRB104 16098 AAS 29398 a

1    lines can achieve cost-effective resolution of system 
2    impacts and warrant investigation of the circumstances 
3    under which those alternatives should be considered and 
4    approved. The alternatives are likely to be beneficial as 
5    investment in electric transmission infrastructure moves 
6    forward.
7        (11) Because transmission planning is conducted 
8    primarily by the regional transmission organizations, the 
9    Commission should be advocating for the State's interests 
10    at the regional transmission organizations to ensure that 
11    such planning facilitates the State's policies and goals, 
12    including overall consumer savings, power system 
13    reliability, economic development, environmental 
14    improvement, and carbon reduction.
15        (12) Advanced transmission technologies have an 
16    important role to play in meeting the State's clean energy 
17    goals. For the purposes of this Section, "advanced 
18    transmission technology" is hardware or software that 
19    provides cost-effective increases to the capacity, 
20    efficiency, or reliability of existing transmission 
21    infrastructure, and includes, but is not limited to: (i) 
22    technology that dynamically adjusts the rated capacity of 
23    transmission lines based on real-time conditions; (ii) 
24    advanced power flow controls used to actively control the 
25    flow of electricity across transmission lines to optimize 
26    usage or relieve congestion; (iii) software or hardware 
 
 
10400SB0025ham004- 636 -LRB104 16098 AAS 29398 a

1    used to identify optimal transmission grid configurations 
2    or enable routing power flows around congestion points; 
3    and (iv) advanced transmission line conductors that have a 
4    direct current electrical resistance at least 10% lower 
5    than existing conductors of a similar diameter on the 
6    transmission system.    
7    (b) Consistent with the findings identified in subsection 
8(a), the Commission shall open an investigation to develop and 
9adopt an initial a renewable energy access plan no later than 
10December 31, 2022. To assist and support the Commission in the 
11development of the plan, the Commission shall retain the 
12services of technical and policy experts with relevant fields 
13of expertise, solicit technical and policy analysis from the 
14public, and provide for a 120-day open public comment period 
15after publication of a draft report, which shall be published 
16no later than 90 days after the comment period ends. The plan 
17shall, at a minimum, do the following:
18        (1) designate renewable energy access plan zones 
19    throughout this State in areas in which renewable energy 
20    resources and suitable land areas are sufficient for 
21    developing generating capacity from renewable energy 
22    technologies;
23        (2) develop a plan to achieve transmission capacity 
24    necessary to deliver the electric output from renewable 
25    energy technologies in the renewable energy access plan 
26    zones to customers in Illinois and other states in a 
 
 
10400SB0025ham004- 637 -LRB104 16098 AAS 29398 a

1    manner that is most beneficial and cost-effective to 
2    customers;
3        (3) use this State's position as an electricity 
4    generation and power transmission hub to create new 
5    investment in this State's renewable energy resources;
6        (4) consider programs, policies, and electric 
7    transmission projects that can be adopted within this 
8    State that promote the cost-effective delivery of power 
9    from renewable energy resources interconnected to the bulk 
10    electric system to meet the renewable portfolio standard 
11    targets under subsection (c) of Section 1-75 of the 
12    Illinois Power Agency Act;
13        (5) consider proposals to improve regional 
14    transmission organizations' regional and interregional 
15    system planning processes, especially proposals that 
16    reduce costs and emissions, create jobs, and increase 
17    State and regional power system reliability to prevent 
18    high-cost outages that can endanger lives, and analyze of 
19    how those proposals would improve reliability and 
20    cost-effective delivery of electricity in Illinois and the 
21    region;
22        (6) make findings and policy recommendations based on 
23    technical and policy analysis regarding locations of 
24    renewable energy access plan zones and the transmission 
25    system developments needed to cost-effectively achieve the 
26    public policy goals identified herein;
 
 
10400SB0025ham004- 638 -LRB104 16098 AAS 29398 a

1        (6.5) make findings and policy recommendations based 
2    on analysis regarding the impact of converting non-powered 
3    dams to hydropower dams relative to the alternative 
4    renewable energy resources; and 
5        (7) present the Commission's conclusions and proposed 
6    recommendations based on its analysis and use the findings 
7    and policy recommendations to determine actions that the 
8    Commission should take.
9    (c) No later than December 31, 2025, and updated no later 
10than 180 days after the effective date of this amendatory Act 
11of the 104th General Assembly to incorporate changes pursuant 
12to this amendatory Act of the 104th General Assembly, and 
13every other year thereafter starting in 2028, the Commission 
14shall open an investigation to develop and adopt a an updated    
15renewable energy access plan update that considers electric 
16transmission projects, transmission policies, transmission 
17alternatives, advanced transmission technologies, other ways 
18to expand capacity on existing or future transmission, and 
19transmission headroom and, at a minimum, : evaluates the 
20implementation and effectiveness of the renewable energy 
21access plan, recommends improvements to the renewable energy 
22access plan, and provides changes to transmission capacity 
23necessary to deliver electric output from the renewable energy 
24access plan zones.
25        (1) evaluates the implementation and effectiveness of 
26    the renewable energy access plan;
 
 
10400SB0025ham004- 639 -LRB104 16098 AAS 29398 a

1        (2) recommends improvements to the renewable energy 
2    access plan;
3        (3) includes updated inputs and assumptions developed 
4    under the integrated resource plan developed and approved 
5    pursuant to Section 16-201 and Section 16-202;
6        (4) may request utilities and other parties to 
7    specifically identify all elements of the existing 
8    transmission system where advanced transmission 
9    technologies are likely to achieve enhanced system 
10    resilience or reliability, reduce potential siting 
11    conflicts or land impacts from the development of new 
12    transmission lines, promote the cost-effective delivery of 
13    power from renewable energy resources interconnected to 
14    the bulk electric system, enable the interconnection of 
15    renewable energy resources, or reduce curtailment of 
16    renewable energy resources. The plan must identify all 
17    elements of the existing transmission system which have 
18    experienced capacity constraints or congestion within the 
19    prior 2 years and explain whether any advanced 
20    transmission technology could reduce or resolve the 
21    capacity constraint or congestion;
22        (5) includes an evaluation of identified and proposed 
23    transmission projects, including proposed advanced 
24    transmission technology projects, based on independent 
25    analysis of costs and benefits, including customer bill 
26    impacts over the life of the project and achievement of 
 
 
10400SB0025ham004- 640 -LRB104 16098 AAS 29398 a

1    State clean energy goals. Projects shall be evaluated in 
2    coordination with other proposals, and may include a 
3    combined evaluation of portfolios of projects;
4        (6) develops a recommended list of transmission 
5    projects and advanced transmission technology projects 
6    that achieve the clean energy public policy objectives of 
7    the State. Nothing in this Section shall limit the 
8    recommended list of transmission projects to those 
9    initially proposed. However, no transmission or advanced 
10    transmission technology project can be included in the 
11    recommended list unless evaluated; and
12        (7) considers additional mechanisms designed to 
13    capture the potential value of geographically diverse 
14    resources that proposed interregional transmission 
15    projects may provide.    
16    The Commission may evaluate options for implementation of 
17the recommended list of transmission projects and advanced 
18transmission technology projects that achieve the clean energy 
19public policy objectives of the State, including through the 
20use of a state agreement approach or a similar structure made 
21available through the relevant regional transmission 
22organizations, and approves final recommendations on 
23implementation.
24    The Commission may invite any interested party to identify 
25transmission projects, including any associated network 
26upgrades, necessary to facilitate achievement of the goals of 
 
 
10400SB0025ham004- 641 -LRB104 16098 AAS 29398 a

1the plan and the most recently approved integrated resource 
2plan. Proposals for projects shall include a description of 
3each project; a proposed target date for completion; an 
4estimated timeline for development; the energy, capacity, and 
5generation profile of renewable generation and energy storage 
6enabled by the project; anticipated new loads served by the 
7project; the proposed technology used, including the use of 
8any advanced transmission technologies; and the status of any 
9permits or approvals necessary. For projects with a target 
10completion date of within 5 years from the date of proposal, 
11the proposal must also include an estimated cost of the 
12project and the proposed routing corridor. The Commission 
13shall aim to complete the updated plan investigation within 12 
14months of opening.
15    (d) Each transmission-owning State utility serving more 
16than 200,000 customers in this State may prepare a plan for 
17integrating advanced transmission technologies into the 
18utility's existing transmission system. The plan must identify 
19all elements of the existing transmission system where 
20advanced transmission technologies are likely to achieve any 
21of the following purposes:
22        (1) enhance system resilience or reliability;
23        (2) reduce potential siting conflicts or land impacts 
24    from the development of new transmission lines;
25        (3) promote the cost-effective delivery of power from 
26    renewable energy resources interconnected to the bulk 
 
 
10400SB0025ham004- 642 -LRB104 16098 AAS 29398 a

1    electric system to meet the renewable portfolio standard 
2    targets under subsection (c) of Section 1-75 of the 
3    Illinois Power Agency Act;
4        (4) enable the interconnection of renewable energy 
5    resources to meet the renewable portfolio standard targets 
6    under subsection (c) of Section 1-75 of the Illinois Power 
7    Agency Act; or
8        (5) reduce curtailment of renewable or zero-carbon 
9    resources.
10    The plan must identify all elements of the existing 
11transmission system which have experienced capacity 
12constraints or congestion within the prior 2 years and explain 
13whether any advanced transmission technology could reduce or 
14resolve the capacity constraint or congestion. Each 
15transmission-owning State utility may submit an advanced 
16transmission technology integration plan to the Commission for 
17consideration as part of the Commission's updated renewable 
18energy access plan investigation under subsection (c). In the 
19Commission's updated renewable energy access plan, the 
20Commission may evaluate, request modifications for, change the 
21timelines of implementation for, and determine the next steps 
22for each advanced transmission integration plan.
23    (e) Each transmission-owning State utility serving more 
24than 200,000 customers in this State may conduct a 
25comprehensive Transmission Headroom Study that shall identify, 
26at a minimum, the points of interconnection with unused, 
 
 
10400SB0025ham004- 643 -LRB104 16098 AAS 29398 a

1existing transmission headroom on the State system, including 
2available capacity behind existing, underutilized points of 
3interconnection, and the amount of available headroom in 
4megawatts at each identified point of interconnection. Each 
5transmission-owning State utility may submit a Transmission 
6Headroom Study to the Commission for consideration as part of 
7the Commission's updated renewable energy access plan 
8investigation under subsection (c).
9    (f) The Commission shall approve an updated renewable 
10energy access plan if it finds that, at a minimum, the evidence 
11in the investigation meets the criteria outlined in subsection 
12(c) and demonstrates that the updated plan will support the 
13clean energy public policy objectives of the State.    
14    (g) The Commission shall notify the applicable regional 
15transmission organizations and utilities of any final 
16recommendations to support the clean energy public policy 
17objectives of the State.
18    (h) Nothing in this Section alters the rights of 
19transmission utilities (i) under rates on file with the 
20Federal Energy Regulatory Commission or the Illinois Commerce 
21Commission, (ii) under orders and determinations of the 
22Federal Energy Regulatory Commission or a regional 
23transmission organization, or (iii) under applicable State 
24laws and policies.
25(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
 
 
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1    (220 ILCS 5/8-513 new)
2    Sec. 8-513. Thermal Energy Network Pilot Program.
3    (a) The Commission shall coordinate with the Illinois 
4Finance Authority, in its role as Climate Bank for the State, 
5to leverage any available federal funding to support thermal 
6energy network pilot projects through the provision of grants 
7or to provide or leverage financing. If that federal funding 
8is not available or not sufficient to meet program objectives, 
9the Commission shall authorize the allocation of up to 
10$20,000,000 to support the thermal energy network pilot 
11projects, to be provided to the Illinois Finance Authority to 
12distribute to projects as a grant or to provide or leverage 
13financing. The Illinois Finance Authority shall submit 
14projects that have already been approved by the Illinois 
15Finance Authority to the Commission for review and approval in 
16a form and manner determined by the Commission. The Commission 
17shall approve projects that it deems to be just, reasonable, 
18and in the public interest. Any allocation of funding shall 
19provide for the Illinois Finance Authority to use a portion of 
20such allocated funds to support its reasonable administrative 
21costs in administering the program under this Section.
22    (b) An electric utility shall be entitled to recover, 
23through tariffed charges approved by the Commission, all of 
24the costs associated with projects authorized for funding by 
25the Commission pursuant to this Section and shall be recovered 
26as part of the utility's costs incurred under Section 45 of the 
 
 
10400SB0025ham004- 645 -LRB104 16098 AAS 29398 a

1Electric Vehicle Act. If any authorized funds have not been 
2recovered by the utility as of January 1, 2029, the 
3Environmental Protection Agency shall allocate the remaining 
4funds to the Illinois Finance Authority as part of its 
5beneficial electrification programs described in Section 45 of 
6the Electric Vehicle Act.    
7    (c) As part of any pilot project proposed pursuant to this 
8Section, the Commission is authorized to approve any specific 
9customer rebates and incentives and any project-specific 
10tariffs and rules. The Commission may create a standard 
11proposed rate structure or minimum requirements for a rate 
12structure to be required of all thermal energy network pilot 
13projects. The Commission may approve the proposed rate 
14structure of a thermal energy network pilot project if the 
15projected heating and cooling costs for end users is not 
16greater than the projected heating and cooling costs the end 
17users would have incurred if the end users had not 
18participated in the program. In its approval process, the 
19Commission shall take into account scenarios where pilot 
20projects enhance comfort and safety for customers through 
21expanded access to affordable heating and cooling.
22    (d) Approved thermal energy network pilot projects shall 
23report to the Commission, on a quarterly basis and until 
24completion of the thermal energy network pilot project, the 
25status of each thermal energy network pilot project. The 
26Commission shall post and make publicly available the reports 
 
 
10400SB0025ham004- 646 -LRB104 16098 AAS 29398 a

1on its website. The reports shall include, but not be limited 
2to:
3        (1) the stage of development of each pilot project;
4        (2) the barriers to development;
5        (3) the number of customers served;
6        (4) the costs of the pilot project;
7        (5) the number of jobs retained or created by the 
8    pilot project;
9        (6) energy savings and fuel savings from the project 
10    and energy consumption by the project; and
11        (7) other information the Commission deems to be in 
12    the public interest or considers likely to prove useful or 
13    relevant to the rulemaking described in subsection (i).
14    (e) Any entity operating a Commission-approved thermal 
15energy network pilot project shall demonstrate that it has 
16entered into a labor peace agreement with a bona fide labor 
17organization that is actively engaged in representing its 
18employees. The labor peace agreement shall apply to the 
19employees necessary for the ongoing maintenance and operation 
20of the thermal energy network. The existence of a labor peace 
21agreement shall be an ongoing material condition of an 
22entity's authorization to maintain and operate the thermal 
23energy networks.
24    (f) Any contractor or subcontractor that performs work on 
25a thermal energy network pilot project under this Section 
26shall be a responsible bidder, as described in Section 30-22 
 
 
10400SB0025ham004- 647 -LRB104 16098 AAS 29398 a

1of the Illinois Procurement Code, and shall certify that not 
2less than prevailing wage, as determined under the Prevailing 
3Wage Act, was or will be paid to the employees who are engaged 
4in construction activities associated with the pilot thermal 
5energy network system. The contractor or subcontractor shall 
6submit evidence to the Commission that it complied with the 
7requirements of this subsection (f). For any approved thermal 
8energy network pilot project, the contractor or subcontractor 
9shall submit evidence that the contractor or subcontractor has 
10entered into a fully executed project labor agreement for the 
11thermal energy network system prior to the initiation of 
12construction activities.
 
13    (220 ILCS 5/9-229)
14    Sec. 9-229. Consideration of attorney and expert 
15compensation as an expense and intervenor compensation fund. 
16    (a) The Commission shall specifically assess the justness 
17and reasonableness of any amount expended by a public utility 
18to compensate attorneys or technical experts to prepare and 
19litigate a general rate case filing. This issue shall be 
20expressly addressed in the Commission's final order.
21    (b) The State of Illinois shall create a Consumer 
22Intervenor Compensation Fund subject to the following:
23        (1) Provision of compensation for consumer interest 
24    representatives Consumer Interest Representatives that 
25    intervene in Illinois Commerce Commission proceedings will 
 
 
10400SB0025ham004- 648 -LRB104 16098 AAS 29398 a

1    increase public engagement, encourage additional 
2    transparency, expand the information available to the 
3    Commission, and improve decision-making.
4        (2) As used in this Section, "consumer Consumer    
5    interest representative" means:
6            (A) a residential utility customer or group of 
7        residential utility customers represented by a 
8        not-for-profit group or organization registered with 
9        the Illinois Attorney General under the Solicitation 
10        for Charity Act;
11            (B) representatives of not-for-profit groups or 
12        organizations whose membership is limited to 
13        residential utility customers; or
14            (C) representatives of not-for-profit groups or 
15        organizations whose membership includes Illinois 
16        residents and that address the community, economic, 
17        environmental, or social welfare of Illinois 
18        residents, except government agencies or intervenors    
19        specifically authorized by Illinois law to participate 
20        in Commission proceedings on behalf of Illinois 
21        consumers.
22        (3) A consumer interest representative is eligible to 
23    receive compensation from the Consumer Intervenor 
24    Compensation Fund consumer intervenor compensation fund if 
25    its participation included lay or expert testimony or 
26    legal briefing and argument concerning the expenses, 
 
 
10400SB0025ham004- 649 -LRB104 16098 AAS 29398 a

1    investments, rate design, rate impact, development of an 
2    integrated resource plan pursuant to Section 16-201 and 
3    any related proceedings, or other matters affecting the 
4    pricing, rates, costs or other charges associated with 
5    utility service and , the Commission does not find the 
6    participation to be immaterial adopts a material 
7    recommendation related to a significant issue in the 
8    docket, and participation caused a significant financial 
9    hardship to the participant; however, no consumer interest 
10    representative shall be eligible to receive an award 
11    pursuant to this Section if the consumer interest 
12    representative receives any compensation, funding, or 
13    donations, directly or indirectly, from parties that have 
14    a financial interest in the outcome of the proceeding. 
15    Funding from residential ratepayers shall not be 
16    considered funding from a party with a financial interest 
17    unless determined to be by the Commission. The Commission 
18    shall determine participation by the consumer interest 
19    representative to be material if recommendations made by 
20    the consumer interest representative are:
21            (A) relevant to issues in the proceeding on which 
22        the Commission makes a finding;
23            (B) supported by facts, such as studies, methods, 
24        or calculations, or by legal or policy analysis; and
25            (C) offered by the consumer interest 
26        representative into evidence in the record of that 
 
 
10400SB0025ham004- 650 -LRB104 16098 AAS 29398 a

1        proceeding, or for legal or policy analysis, are filed 
2        in the docket of that proceeding, through briefing, 
3        motion, or other method.    
4        (4) Within 30 days after September 15, 2021 (the 
5    effective date of Public Act 102-662), each utility that 
6    files a request for an increase in rates under Article IX 
7    or Article XVI shall deposit an amount equal to one half of 
8    the rate case attorney and expert expense allowed by the 
9    Commission, but not to exceed $500,000, into the fund 
10    within 35 days of the date of the Commission's final Order 
11    in the rate case or 20 days after the denial of rehearing 
12    under Section 10-113 of this Act, whichever is later. The 
13    Consumer Intervenor Compensation Fund shall be used to 
14    provide payment to consumer interest representatives as 
15    described in this Section.
16        (5) An electric public utility with 3,000,000 or more 
17    retail customers shall contribute $450,000 to the Consumer 
18    Intervenor Compensation Fund within 60 days after 
19    September 15, 2021 (the effective date of Public Act 
20    102-662). A combined electric and gas public utility 
21    serving fewer than 3,000,000 but more than 500,000 retail 
22    customers shall contribute $225,000 to the Consumer 
23    Intervenor Compensation Fund within 60 days after 
24    September 15, 2021 (the effective date of Public Act 
25    102-662). A gas public utility with 1,500,000 or more 
26    retail customers that is not a combined electric and gas 
 
 
10400SB0025ham004- 651 -LRB104 16098 AAS 29398 a

1    public utility shall contribute $225,000 to the Consumer 
2    Intervenor Compensation Fund within 60 days after 
3    September 15, 2021 (the effective date of Public Act 
4    102-662). A gas public utility with fewer than 1,500,000 
5    retail customers but more than 300,000 retail customers 
6    that is not a combined electric and gas public utility 
7    shall contribute $80,000 to the Consumer Intervenor 
8    Compensation Fund within 60 days after September 15, 2021 
9    (the effective date of Public Act 102-662). A gas public 
10    utility with fewer than 300,000 retail customers that is 
11    not a combined electric and gas public utility shall 
12    contribute $20,000 to the Consumer Intervenor Compensation 
13    Fund within 60 days after September 15, 2021 (the 
14    effective date of Public Act 102-662). A combined electric 
15    and gas public utility serving fewer than 500,000 retail 
16    customers shall contribute $20,000 to the Consumer 
17    Intervenor Compensation Fund within 60 days after 
18    September 15, 2021 (the effective date of Public Act 
19    102-662). A water or sewer public utility serving more 
20    than 100,000 retail customers shall contribute $80,000, 
21    and a water or sewer public utility serving fewer than 
22    100,000 but more than 10,000 retail customers shall 
23    contribute $20,000.
24        (6)(A) Prior to the entry of a final order Final Order    
25    in a docketed case, the Commission Administrator shall 
26    provide a payment to a consumer interest representative 
 
 
10400SB0025ham004- 652 -LRB104 16098 AAS 29398 a

1    that demonstrates through a verified application for 
2    funding that the consumer interest representative's 
3    participation or intervention without an award of fees or 
4    costs imposes a significant financial cost for the 
5    consumer interest representative hardship based on a 
6    schedule to be developed by the Commission. The 
7    Administrator may require verification of costs expected 
8    to be incurred, including statements of expected hours 
9    spent, as a condition to paying the consumer interest 
10    representative prior to the entry of a final order Final 
11    Order in a docketed case. The upfront payment prior to the 
12    entry of a final order in the relevant docketed case shall 
13    be subject to the reconciliation process described in 
14    subparagraph (C) of this paragraph. For purposes of 
15    upfront payments provided for under this subparagraph, and 
16    provided the testimony or legal argument was offered into 
17    evidence or filed in the docket, a decision by the 
18    Commission prior to entry of a final order that a consumer 
19    interest representative's evidence or legal argument is 
20    relevant to issues in the proceeding under subparagraph 
21    (A) of paragraph (3) shall not be subject to 
22    reconsideration. Any compensation awarded shall be subject 
23    to review and reconciliation under subparagraph (C) of 
24    this paragraph. Payments made after the issuance of a 
25    final order in the relevant docketed case do not require 
26    the reconciliation.    
 
 
10400SB0025ham004- 653 -LRB104 16098 AAS 29398 a

1        (B) If the Commission does not find the participation 
2    to be immaterial adopts a material recommendation related 
3    to a significant issue in the docket and participation 
4    caused a financial hardship to the participant, then the 
5    consumer interest representative shall be allowed payment 
6    for some or all of the consumer interest representative's 
7    reasonable attorney's or advocate's fees, reasonable 
8    expert witness fees, and other reasonable costs of 
9    preparation for and participation in a hearing or 
10    proceeding. Expenses related to travel or meals shall not 
11    be compensable. Expenses incurred by participation in 
12    workshops or other informal processes outside a docketed 
13    proceeding shall not be compensable. Attorneys and expert 
14    witnesses who represent or testify for more than one party 
15    in the same docketed proceeding and perform essentially 
16    the same work on behalf of the parties shall not be 
17    compensated more than once for those same services 
18    rendered in that proceeding.    
19        (C) The consumer interest representative shall submit 
20    an itemized request for compensation to the Consumer 
21    Intervenor Compensation Fund, including the advocate's or 
22    attorney's reasonable fee rate, the number of hours 
23    expended, reasonable expert and expert witness fees, and 
24    other reasonable costs for the preparation for and 
25    participation in the hearing and briefing within 30 days 
26    after of the Commission's final order or the Commission's    
 
 
10400SB0025ham004- 654 -LRB104 16098 AAS 29398 a

1    after denial or decision on rehearing, if any, whichever 
2    is later. If compensation is provided prior to the entry 
3    of a final order in a docketed case, such compensation 
4    shall be adjusted following the final order to reconcile 
5    the difference between actual eligible expenses incurred 
6    and the amount of compensation provided prior to the entry 
7    of the final order. The reconciliation adjustment shall 
8    ensure that the total compensation awarded to the 
9    applicant is no more and no less than the actual eligible 
10    expenses incurred. Payments made after the issuance of a 
11    final order in the relevant docketed case do not require 
12    the reconciliation.    
13        (7) Administration of the Fund.
14        (A) The Consumer Intervenor Compensation Fund is 
15    created as a special fund in the State treasury. All 
16    disbursements from the Consumer Intervenor Compensation 
17    Fund shall be made only upon warrants of the Comptroller 
18    drawn upon the Treasurer as custodian of the Fund upon 
19    vouchers signed by the Executive Director of the 
20    Commission or by the person or persons designated by the 
21    Director for that purpose. The Comptroller is authorized 
22    to draw the warrant upon vouchers so signed. The Treasurer 
23    shall accept all warrants so signed and shall be released 
24    from liability for all payments made on those warrants. 
25    The Consumer Intervenor Compensation Fund shall be 
26    administered by an Administrator that is a person or 
 
 
10400SB0025ham004- 655 -LRB104 16098 AAS 29398 a

1    entity that is independent of the Commission. The 
2    administrator will be responsible for the prudent 
3    management of the Consumer Intervenor Compensation Fund 
4    and for recommendations for the award of consumer 
5    intervenor compensation from the Consumer Intervenor 
6    Compensation Fund. The Commission shall issue a request 
7    for qualifications for a third-party program administrator 
8    to administer the Consumer Intervenor Compensation Fund. 
9    The third-party administrator shall be chosen through a 
10    competitive bid process based on selection criteria and 
11    requirements developed by the Commission. The Illinois 
12    Procurement Code does not apply to the hiring or payment 
13    of the Administrator. All Administrator costs may be paid 
14    for using monies from the Consumer Intervenor Compensation 
15    Fund, but the Program Administrator shall strive to 
16    minimize costs in the implementation of the program.
17        (B) The computation of compensation awarded from the 
18    fund shall take into consideration the market rates paid 
19    to persons of comparable training and experience who offer 
20    similar services, but may not exceed the comparable market 
21    rate for services paid by the public utility as part of its 
22    rate case expense.
23        (C)(1) Recommendations on the award of compensation by 
24    the administrator shall include consideration of whether 
25    the participation was material Commission adopted a 
26    material recommendation related to a significant issue in 
 
 
10400SB0025ham004- 656 -LRB104 16098 AAS 29398 a

1    the docket and whether participation caused a financial 
2    hardship to the participant and the payment of 
3    compensation is fair, just and reasonable.
4        (2) Recommendations on the award of compensation by 
5    the administrator shall be submitted to the Commission for 
6    approval within 30 days after when the application for 
7    funding is submitted to the administrator. Unless the 
8    Commission initiates an investigation within 60 45 days 
9    after an application for funding is submitted to the 
10    administrator, the Commission shall within 90 days after 
11    the application is submitted to the administrator, or as 
12    soon as practicable thereafter, award funding to the 
13    applicant. Notice of the administrator's award 
14    recommendation the notice to the Commission, the award of 
15    compensation shall be allowed 45 days after notice to the 
16    Commission. Such notice shall be given by filing with the 
17    Commission on the Commission's e-docket system, and 
18    keeping open for public inspection the award for 
19    compensation proposed by the Administrator. The Commission 
20    shall have power, and it is hereby given authority, either 
21    upon complaint or upon its own initiative without 
22    complaint, at once, and if it so orders, without answer or 
23    other formal pleadings, but upon reasonable notice, to 
24    enter upon a hearing concerning the propriety of the 
25    award.
26    (c) The Commission may adopt rules to implement this 
 
 
10400SB0025ham004- 657 -LRB104 16098 AAS 29398 a

1Section.
2(Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)
 
3    (220 ILCS 5/16-105.17)
4    Sec. 16-105.17. Multi-Year Integrated Grid Plan.
5    (a) The General Assembly finds that ensuring alignment of 
6regulated utility operations, expenditures, and investments 
7with public benefit goals, including safety, reliability, 
8resiliency, affordability, equity, emissions reductions, and 
9expansion of clean distributed energy resources, is critical 
10to maximizing the benefits of the interconnected utility grid 
11and cost-effective utility expenditures on the grid. It is the 
12policy of the State to promote inclusive, comprehensive, 
13transparent, cost-effective distribution system planning and 
14disclosures processes that minimize long-term costs for 
15Illinois customers and support the achievement of State 
16renewable energy development and other clean energy, public 
17health, and environmental policy goals. Utility distribution 
18system expenditures, programs, investments, and policies must 
19be evaluated in coordination with these goals. In particular, 
20the General Assembly finds that:
21        (1) Investment in infrastructure to support and enable 
22    existing and new distributed energy resources creates 
23    significant economic development, environmental, and 
24    public health benefits in the State.
25        (2) Illinois' electricity distribution system must 
 
 
10400SB0025ham004- 658 -LRB104 16098 AAS 29398 a

1    cost-effectively integrate renewable energy resources, 
2    including utility-scale renewable energy resources, 
3    community renewable generation, and distributed renewable 
4    energy resources, support beneficial electrification, 
5    including electric vehicle use and adoption, promote 
6    opportunities for third-party investment in 
7    nontraditional, grid-related technologies and resources 
8    such as batteries, solar photovoltaic panels, and smart 
9    thermostats, reduce energy usage generally and especially 
10    during times of greatest reliance on fossil fuels, and 
11    enhance customer engagement opportunities.
12        (3) Inclusive distribution system planning is an 
13    essential tool for the Commission, public utilities, and 
14    stakeholders to effectively coordinate environmental, 
15    consumer, reliability, and equity goals at fair and 
16    reasonable costs, and for ensuring transparent utility 
17    accountability for meeting those goals.
18        (4) Any planning process should advance Illinois 
19    energy policy goals while ensuring utility investments are 
20    cost-effective. Such a process should maximize the sharing 
21    of information, minimize overlap with existing filing 
22    requirements to ensure robust stakeholder participation, 
23    and recognize the responsibility of the utility to manage 
24    the grid in a safe, reliable manner.
25        (5) The General Assembly is concerned that, in the 
26    absence of a transparent, meaningful distribution system 
 
 
10400SB0025ham004- 659 -LRB104 16098 AAS 29398 a

1    planning process, utility investments may not always serve 
2    customers' best interests, appropriately promote the 
3    expansion of clean distributed energy resources, and 
4    advance equity and environmental justice.
5        (6) The General Assembly is also encouraged by the 
6    opportunities presented by nontraditional solutions to 
7    utility, customer, and grid needs that may be more 
8    efficient and cost-effective, and less environmentally 
9    harmful than traditional solutions. Nontraditional 
10    solutions include distributed energy resources owned or 
11    implemented by customers and independent third parties, 
12    controllable load, beneficial electrification, or rate 
13    design that encourages efficient energy use.
14        (7) The General Assembly finds that Illinois 
15    utilities' current processes for planning their 
16    distribution system should be made more accessible and 
17    transparent to individuals and communities, and that more 
18    inclusive and accessible distribution system planning 
19    processes would be in the interests of all Illinois 
20    residents.
21        (8) The General Assembly finds it would be beneficial 
22    to require utilities to demonstrate how their spending 
23    promotes identified State clean energy goals, such as 
24    integrating renewable energy, empowering customers to make 
25    informed choices, supporting electric vehicles, beneficial 
26    electrification, and energy storage, achieving equity 
 
 
10400SB0025ham004- 660 -LRB104 16098 AAS 29398 a

1    goals, enhancing resilience, and maintaining reliability.
2    The General Assembly therefore directs the utilities to 
3implement distribution system planning as described in this 
4Section in order to accelerate progress on Illinois clean 
5energy and environmental goals and hold electric utilities 
6publicly accountable for their performance.
7    (b) Unless otherwise specified, the terms used in this 
8Section shall have the same meanings as defined in Sections 
916-102 and 16-107.6. As used in this Section:
10    "Demand response" means measures that decrease peak 
11electricity demand or shift demand from peak to off-peak 
12periods.
13    "Distributed energy resources" or "DER" means a wide range 
14of technologies that are connected to the grid, including 
15those that are located on the customer side of the customer's 
16electric meter and can provide value to the distribution 
17system, including, but not limited to, distributed generation, 
18energy storage, electric vehicles, and demand response 
19technologies.
20    "Environmental justice communities" means the definition 
21of that term based on existing methodologies and findings, 
22used and as may be updated by the Illinois Power Agency and its 
23Program Administrator in the Illinois Solar for All Program.
24    (c) This Section applies to electric utilities serving 
25more than 500,000 retail customers in the State.
26    (d) The Multi-Year Integrated Grid Plan ("the Plan") shall 
 
 
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1be designed to:
2        (1) ensure coordination of the State's renewable 
3    energy goals, climate and environmental goals with the 
4    utility's distribution system investments, and programs 
5    and policies over a 5-year planning horizon to maximize 
6    the benefits of each while ensuring utility expenditures 
7    are cost-effective;
8        (2) optimize utilization of electricity grid assets 
9    and resources to minimize total system costs;
10        (3) support efforts to bring the benefits of grid 
11    modernization and clean energy, including, but not limited 
12    to, deployment of distributed energy resources, to all 
13    retail customers, and support efforts to bring at least 
14    40% of the benefits of those benefits to Equity Investment 
15    Eligible Communities. Nothing in this paragraph is meant 
16    to require a specific amount of spending in a particular 
17    geographic area;
18        (4) enable greater customer engagement, empowerment, 
19    and options for energy services;
20        (5) reduce grid congestion, minimize the time and 
21    expense associated with interconnection, and increase the 
22    capacity of the distribution grid to host increasing 
23    levels of distributed energy resources, to facilitate 
24    availability and development of distributed energy 
25    resources, particularly in locations that enhance consumer 
26    and environmental benefits;
 
 
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1        (6) ensure opportunities for robust public 
2    participation through open, transparent planning 
3    processes.
4        (7) provide for the analysis of the cost-effectiveness 
5    of proposed system investments, which takes into account 
6    environmental costs and benefits;
7        (8) to the maximum extent practicable, achieve or 
8    support the achievement of Illinois environmental goals, 
9    including those described in Section 9.10 of the 
10    Environmental Protection Act and Section 1-75 of the 
11    Illinois Power Agency Act, and emissions reductions 
12    required to improve the health, safety, and prosperity of 
13    all Illinois residents;
14        (9) support existing Illinois policy goals promoting 
15    the long-term growth of energy efficiency, demand 
16    response, and investments in renewable energy resources;
17        (10) provide sufficient public information to the 
18    Commission, stakeholders, and market participants in order 
19    to enable nonemitting customer-owned or third-party 
20    distributed energy resources, acting individually or in 
21    aggregate, to seamlessly and easily connect to the grid, 
22    provide grid benefits, support grid services, and achieve 
23    environmental outcomes, without necessarily requiring 
24    utility ownership or controlling interest over those 
25    resources, and enable those resources to act as 
26    alternatives to utility capital investments; and
 
 
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1        (11) provide delivery services at rates that are 
2    affordable to all customers, including low-income 
3    customers.
4    (e) Plan Development Stakeholder Process.
5        (1) To promote the transparency of utility 
6    distributions system planned investments and the planning 
7    process for those investments, the Commission shall 
8    convene a workshop process, over a period of no less than 5 
9    months, for each such utility for the purpose of 
10    establishing an open, inclusive, and cooperative forum 
11    regarding such investments. The workshops shall be 
12    facilitated by an independent, third-party facilitator 
13    selected by the Commission. Data and projections provided 
14    through the workshop process shall be designed to provide 
15    participants with information about the electric utility's 
16    (i) historic distribution system investments for at least 
17    the 5 years prior to the year in which the workshop is held 
18    and (ii) planned investments for the 5-year period 
19    following the year in which the workshop is held. The 
20    workshop process shall recognize that estimates for later 
21    years will be less reliable and indicative of future 
22    conduct than estimates for earlier years and that the 
23    electric utility is subject to financial and system 
24    planning processes. No later than January 1, 2022, the 
25    facilitator shall initiate a series of workshops for each 
26    electric utility subject to this Section. The series of 
 
 
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1    workshops shall include no fewer than 6 workshops and 
2    shall conclude no later than June 1, 2022.
3        (2) The workshops shall be designed to achieve the 
4    following objectives:
5            (A) review utilities' planned capital investments 
6        and supporting data;
7            (B) review how utilities plan to invest in their 
8        distribution system in order to meet the system's 
9        projected needs;
10            (C) review system and locational data on 
11        reliability, resiliency, DER, and service quality 
12        provided by the utilities;
13            (D) solicit and consider input from diverse 
14        stakeholders, including representatives from 
15        environmental justice communities, geographically 
16        diverse communities, low-income representatives, 
17        consumer representatives, environmental 
18        representatives, organized labor representatives, 
19        third-party technology providers, and utilities;
20            (E) consider proposals from utilities and 
21        stakeholders on programs and policies necessary to 
22        achieve the objectives in subsection (d) of this 
23        Section;
24            (F) consider proposals applicable to each 
25        component of the utilities' Multi-Year Integrated Grid 
26        Plan filings under paragraph (2) of subsection (f) of 
 
 
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1        this Section;
2            (G) educate and equip interested stakeholders so 
3        that they can effectively and efficiently provide 
4        feedback and input to the electric utility; and
5            (H) review planned capital investment to ensure 
6        that delivery services are provided at rates that are 
7        affordable to all customers, including low-income 
8        customers.
9        (3) To the extent any of the information in 
10    subparagraphs (A) through (H) of paragraph (2) of this 
11    subsection is designated as confidential and proprietary 
12    under the Commission's rules, the proponent of the 
13    designation shall have the burden of making the requisite 
14    showing under the Commission's rules. For data that is 
15    determined to be confidential or that includes personally 
16    identifiable information, the Commission may develop 
17    procedures and processes to enable data sharing with 
18    parties and stakeholders while ensuring the 
19    confidentiality of the information.
20        (4) Workshops should be organized and facilitated in a 
21    manner that encourages representation from diverse 
22    stakeholders, ensuring equitable opportunities for 
23    participation, without requiring formal intervention or 
24    representation by an attorney. Workshops should be held 
25    during both day and evening hours, in a variety of 
26    locations within each electric utility's service 
 
 
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1    territory, and should allow remote participation.
2        (5) It is a goal of the State that this workshop 
3    process will provide a forum for interested stakeholders 
4    to effectively and efficiently provide feedback and input 
5    to the electric utility. It is also a goal of the State 
6    that stakeholder participation in this process will 
7    prepare stakeholders to more capably participate in 
8    Multi-Year Rate Plan proceedings conducted pursuant to 
9    Section 16-108.18 of this Act, if they so elect. As part of 
10    the workshop process, the electric utility shall submit to 
11    the Commission the electric utility's capital investments 
12    proposal, and supporting data described in subparagraphs 
13    (A) through (C) of paragraph (2) of this subsection (e) 
14    before the start of workshops to allow interested 
15    stakeholders to reasonably review data before attending 
16    workshops. The Commission shall make public the utility 
17    capital investments proposal by posting it on the 
18    Commission's website and set the location and time of any 
19    workshop to be held as part of the workshop process, and 
20    establish a data request process, consistent with the 
21    Commission's rules, that affords workshop participants 
22    opportunities to submit data requests to the utility, and 
23    receive responses in accordance with the utility's 
24    obligations under the law, prior to the workshop, 
25    regarding the information described in this paragraph (5). 
26    Upon the written request of a workshop participant, the 
 
 
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1    utility shall also present at a given workshop at least 
2    one appropriate company representative who can address the 
3    specific written questions or written categories of 
4    questions identified in advance by the workshop 
5    participant regarding issues related to the utility's 
6    Multi-Year Integrated Grid Plan. To facilitate public 
7    feedback, the administrator facilitating the workshops 
8    shall, throughout the workshop process, develop questions 
9    for stakeholder input on topics being considered. This may 
10    include, but is not limited to: design of the workshop 
11    process, locational data and information provided by 
12    utilities, alignment of plans, programs, investments and 
13    objectives, and other topics as deemed appropriate by the 
14    Commission facilitation staff. Stakeholder feedback shall 
15    not be limited to these questions. The information 
16    provided as part of the workshop process pursuant to this 
17    subsection (e) is intended to be informational and to 
18    provide a preliminary view of costs and investments, which 
19    may change. Accordingly, the information provided pursuant 
20    to this subsection (e) shall not be binding on the utility 
21    and shall not be the sole basis for a finding in any 
22    Commission proceeding of imprudence, unreasonableness, or 
23    lack of use or usefulness of any individual or aggregate 
24    level of utility plant or other investment or expenditure 
25    addressed; however, information contained in the plan may 
26    be used in a proceeding before the Commission, with weight 
 
 
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1    of such evidence to be determined by the Commission.
2        (6) Workshops shall not be considered settlement 
3    negotiations, compromise negotiations, or offers to 
4    compromise for the purposes of Illinois Rule of Evidence 
5    408. All materials shared as a part of the workshop 
6    process, and that are not determined to be confidential as 
7    described in paragraph (3) of this subsection (e), shall 
8    be made publicly available on a website made available by 
9    the Commission.
10        (7) On conclusion of the workshops, the Commission 
11    shall open a comment period that allows interested and 
12    diverse stakeholders to submit comments and 
13    recommendations regarding the utility's Multi-Year 
14    Integrated Grid Plan filing. Based on the workshop process 
15    and stakeholder comments and recommendations offered 
16    verbally or in writing during the workshops and in writing 
17    during the comment period following the workshops, the 
18    independent third-party facilitator shall prepare a 
19    report, to be submitted to the Commission no later than 
20    July 1, 2022, describing the stakeholders, discussions, 
21    proposals, and areas of consensus and disagreement from 
22    the workshop process, and making recommendations to the 
23    Commission regarding the utility's Multi-Year Integrated 
24    Grid Plan. Interested stakeholders shall have an 
25    opportunity to provide comment on the independent 
26    third-party facilitator report.
 
 
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1        (8) Based on discussions in the workshops, the 
2    independent third-party facilitator report, and 
3    stakeholder comments and recommendations made during and 
4    following the workshop process, the Commission shall issue 
5    initiating orders no later than August 1, 2022, requiring 
6    the electric utilities subject to this Section to file the 
7    first Multi-Year Integrated Grid Plan no later than 
8    January 20, 2023. The initiating orders shall specify the 
9    requirements applicable to the utilities' Multi-Year 
10    Integrated Grid Plans, which shall supplement and not 
11    replace those requirements described in subsection (f) of 
12    this Section.
13    (f) Multi-Year Integrated Grid Plan.
14        (1) Pursuant to this subsection (f) and the initiating 
15    orders of the Commission, each electric utility subject to 
16    this Section shall, no later than January 20, 2023, submit 
17    its first Multi-Year Integrated Grid Plan. No later than 
18    January 20, 2026, and every 4 years thereafter, the 
19    utility shall submit its subsequent Plan. Each Plan shall:
20            (A) incorporate requirements established by the 
21        Commission in its initiating order; and
22            (B) propose distribution system investment 
23        programs, policies, and plans designed to optimize 
24        achievement of the objectives set forth in subsection 
25        (d) of this Section and achieve the metrics approved 
26        by the Commission pursuant to Section 16-108.18 of 
 
 
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1        this Act.
2        To the extent practicable and reasonable, all 
3    programs, policies, and initiatives proposed by the 
4    utility in its plan should be informed by stakeholder 
5    input received during the workshop process pursuant to 
6    subsection (e) of this Section. Where specific stakeholder 
7    input has not been incorporated in proposed programs, 
8    policies, and plans, the electric utility shall provide an 
9    explanation as to why that input was not incorporated.
10        (2) In order to ensure electric utilities' ability to 
11    meet the goals and objectives set forth in this Section, 
12    the Multi-Year Integrated Grid Plans must include, at 
13    minimum, the following information:
14            (A) A description of the utility's distribution 
15        system planning process, including:
16                (i) the overview of the process, including 
17            frequency and duration of the process, roles, and 
18            responsibilities of utility personnel and 
19            departments involved;
20                (ii) a summary of the meetings with 
21            stakeholders conducted prior to filing of the plan 
22            with the Commission.
23                (iii) the description of any coordination of 
24            the processes with any other planning process 
25            internal or external to the utility, including 
26            those required by a regional transmission 
 
 
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1            operator.
2            (B) A detailed description of the current 
3        operating conditions for the distribution system 
4        separately presented for each of the utility's 
5        operating areas, where possible, including a detailed 
6        description, with supporting data, of system 
7        conditions, including baseline data regarding the 
8        utility's distribution system from the utility's 
9        annual report to the Commission, total distribution 
10        system substation capacity in kVa, total miles of 
11        primary overhead distribution wire, and total miles of 
12        primary underground distribution cable, distributed 
13        energy resource deployment by type, size, customer 
14        class, and geographic dispersion as to those DERs that 
15        have completed the interconnection process, the most 
16        current distribution line loss study, current and 
17        expected System Average Interruption Frequency Index 
18        and Customer Average Interruption Duration Index data 
19        for the system, identification of the system model 
20        software currently used and planned software 
21        deployments, and other data needs as requested by the 
22        Commission or as determined through Commission rules. 
23        The description shall also include the utility's most 
24        recent system load and peak demand forecast for at 
25        least the next 5 years, and up to 10 years if 
26        available, a discussion of how the forecast was 
 
 
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1        prepared and how distributed energy resources and 
2        energy efficiency were factored into the forecast, and 
3        identification of the forecasting software currently 
4        used and planned software deployments.
5            (C) Financial Data.
6                (i) For each of the preceding 5 years, the 
7            utility's distribution system investments by the 
8            investment categories tracked by the utility, 
9            including, but not limited to, new business, 
10            facility relocation, capacity expansion, system 
11            performance, preventive maintenance, corrective 
12            maintenance, the total amount of investments 
13            associated with the integration of DERs, the total 
14            amount of charges to DER developers and retail 
15            customers for interconnection of DERs to the 
16            distribution system, and a list of each major 
17            investment category the utility used to maintain 
18            its routine standing operational activities and 
19            the associated plant in service amount for each 
20            category in which the plant in service amount is 
21            at least $2,000,000;
22                (ii) For each of the preceding 5 years, data 
23            on and a discussion of the utility's distribution 
24            system operation and maintenance expenses;
25                (iii) A 5-year long-range forecast of 
26            distribution system capital investments and 
 
 
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1            operational and maintenance expenses, including a 
2            discussion of any projections for expenses for the 
3            categories listed in subparagraph (i) of this item 
4            (C).
5            (D) System data on DERs on the utility's 
6        distribution system, including the total number and 
7        nameplate capacity of DERs that completed 
8        interconnection in the prior year, current DER 
9        deployment by type, size, and geographic dispersion, 
10        to the extent that granular geographic information 
11        does not disclose personally identifiable information, 
12        and other data as requested by the Commission or 
13        determined by Commission rules.
14            (E) Hosting Capacity and Interconnection 
15        Requirements.
16                (i) The utility shall make available on its 
17            website the hosting capacity analysis results that 
18            shall include mapping and GIS capability, as well 
19            as any other requirements requested by the 
20            Commission or determined through Commission rules. 
21            The plan shall identify where the hosting capacity 
22            analysis results shall be made publicly available. 
23            This shall also include an assessment of the 
24            impact of utility investments over the next 5 
25            years on hosting capacity and a narrative 
26            discussion of how the hosting capacity analysis 
 
 
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1            advances customer-sited distributed energy 
2            resources, including electric vehicles, energy 
3            storage systems, and photovoltaic resources, and 
4            how the identification of interconnection points 
5            on the distribution system will support the 
6            continued development of distributed energy 
7            resources.
8                (ii) Discussion of the utility's 
9            interconnection requirements and how they comply 
10            with the Commission's applicable regulations.
11            (F) Identification and discussion of the scenarios 
12        considered in the development of the utility's 
13        Multi-Year Integrated Grid Plan, including DER 
14        scenarios, and discussion of base-case and alternative 
15        scenarios, how the scenarios were developed and 
16        selected, and how the scenarios include a reasonable 
17        mix of DERs scenarios, types, and geographic 
18        dispersion. Scenarios shall at least consider the 
19        5-year forecast horizon of the Multi-Year Integrated 
20        Grid Plan, but may also consider longer-term scenarios 
21        where data is available. The plan shall also include 
22        requirements requested by the Commission or determined 
23        through Commission rules.
24            (G) An evaluation of the short-term and long-run 
25        benefits and costs of distributed energy resources 
26        located on the distribution system, including, but not 
 
 
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1        limited to, the locational, temporal, and 
2        performance-based benefits and costs of distributed 
3        energy resources. The utility shall use the results of 
4        this evaluation to inform its analysis of Solution 
5        Sourcing Opportunities, including nonwires 
6        alternatives, under subparagraph (K) of paragraph (2) 
7        subsection (f) of this Section. The Commission may use 
8        the data produced through this evaluation to, among 
9        other use-cases, inform the Commission's investigation 
10        and establishment of tariffs and compensation for 
11        distributed energy resources interconnecting to the 
12        utility's distribution system, including rebates 
13        provided by the electric utility pursuant to Section 
14        16-107.6 of this Act.
15            (H) Long-term Distribution System Investment Plan.
16                (i) The utility's planned distribution capital 
17            investments for the period covered by the planning 
18            process required by this Section, by the 
19            investment categories used by the utility, and 
20            with discussion of any individual planned projects 
21            with a planned total investment gross amount of 
22            $3,000,000 or more and of the alternatives 
23            considered by the utility to such individual 
24            projects including any non-traditional 
25            alternatives and DER alternatives, and supporting 
26            data. This shall provide sufficiently detailed 
 
 
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1            explanations of how the planned investments shall 
2            support the goals in subsection (d) of this 
3            Section.
4                (ii) Discussion of how the utility's capital 
5            investments plan is consistent with Commission 
6            orders regarding the procurement of renewable 
7            resources as discussed in Section 16-111.5 of this 
8            Act, energy efficiency plans as discussed in 
9            Section 8-103B, distributed generation rebates as 
10            discussed in Section 16-107.6, and any other 
11            Commission order affecting the goals described in 
12            subsection (d) of this Section.
13                (iii) A plan for achieving the applicable 
14            metrics that were approved by the Commission for 
15            the utility pursuant to subsection (e) of Section 
16            16-108.18 of this Act.
17                (iv) A narrative discussion of the utility's 
18            vision for the distribution system over the next 5 
19            years.
20                (v) Any additional information requested by 
21            the Commission or determined through Commission 
22            rules.
23            (I) A detailed description of historic 
24        distribution system operations and maintenance 
25        expenditures for the preceding 5 years and of planned 
26        or projected operations and maintenance expenditures 
 
 
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1        for the period covered by the planning process 
2        required by this Section, as well as the data, 
3        reasoning and explanation supporting planned or 
4        projected expenditures. Any additional information 
5        requested by the Commission or determined through 
6        Commission rules.
7            (J) A detailed plan for achieving the applicable 
8        metrics that were approved by the Commission for the 
9        utility pursuant to subsection (e) of Section 
10        16-108.18 of this Act, including, but not limited to, 
11        the following:
12                (i) A description of, exclusive of low-income 
13            rate relief programs and other income-qualified 
14            programs, how the utility is supporting efforts to 
15            bring 40% of benefits from programs, policies, and 
16            initiatives proposed in their Multi-Year 
17            Integrated Grid Plan to ratepayers in low-income 
18            and environmental justice communities. This shall 
19            also include any information requested by the 
20            Commission or determined through Commission rules. 
21            Nothing in this subparagraph is meant to require a 
22            specific amount of spending in a particular 
23            geographic area.
24                (ii) A detailed analysis of current and 
25            projected flexible resources, including resource 
26            type, size (in MW and MWh), location and 
 
 
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1            environmental impact, as well as anticipated needs 
2            that can be met using flexible resources, to meet 
3            the goals described in subsection (d) of this 
4            Section, to meet the applicable metrics that were 
5            approved by the Commission for the utility 
6            pursuant to subsection (e) of Section 16-108.18 of 
7            this Act, and any other Commission order affecting 
8            the goals described in subsection (d) of this 
9            Section.
10                (iii) Any additional information requested by 
11            the Commission or determined through Commission 
12            rules.
13            (K) Identification of potential cost-effective 
14        solutions from nontraditional and third-party owned 
15        investments that could meet anticipated grid needs, 
16        including, but not limited to, distributed energy 
17        resources procurements, tariffs or contracts, 
18        programmatic solutions, rate design options, 
19        technologies or programs that facilitate load 
20        flexibility, nonwires alternatives, and other 
21        solutions that are intended to meet the objectives 
22        described at subsection (d). It is the policy of this 
23        State that cost-effective third-party or 
24        customer-owned distributed energy resources create 
25        robust competition and customer choice and shall be 
26        considered as appropriate. The Commission shall 
 
 
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1        establish rules determining data or methods for 
2        Solution Sourcing Opportunities.
3            (L) A detailed description of the utility's 
4        interoperability plan, which must describe the manner 
5        in which the electric utility's current and planned 
6        distribution system investments will work together and 
7        exchange information and data, the extent to which the 
8        utility is implementing open standards and interfaces 
9        with third-party distributed energy resource owners 
10        and aggregators, and the utility's plan for 
11        interoperability testing and certification.
12            (M) For plans that include a time period that is 
13        after January 1, 2029, a description of efforts to 
14        support transportation electrification through the 
15        following:
16                (i) make-ready investments and other programs 
17            to facilitate the rapid deployment of charging 
18            equipment throughout this State, especially 
19            deployment that targets medium-duty and heavy-duty 
20            vehicle electrification and multi-unit buildings;
21                (ii) the development and implementation of (1) 
22            time-of-use rates and their benefit for electric 
23            vehicle users and for all customers, (2) optimized 
24            charging programs to achieve identified savings, 
25            and (3) new contracts and compensation for 
26            services in the optimized charging programs, 
 
 
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1            through signals that allow electric vehicle 
2            charging to respond to local system conditions, 
3            manage critical peak periods, serve as a demand 
4            response or peak resource, and maximize renewable 
5            energy use and integration into the grid; and
6                (iii) commercial tariffs utilizing 
7            alternatives to traditional demand-based rate 
8            structures that facilitate charging for 
9            light-duty, heavy-duty, and fleet electric 
10            vehicles.
11                For items (i) through (iii), the utility shall 
12            demonstrate methods of minimizing ratepayer 
13            impacts and exempting or minimizing, to the extent 
14            possible, low-income ratepayers from the costs 
15            associated with facilitating the expansion of 
16            electric vehicle charging. Investments, programs, 
17            and activities proposed to meet the obligations of 
18            this subparagraph (M) shall be evaluated and 
19            approved by the Commission using the same 
20            standards of cost-effectiveness, as described in 
21            paragraph (7) of subsection (d), and not be 
22            subject to evaluation standards applied to other 
23            investments, programs, and activities, such as 
24            energy efficiency programs.    
25        (3) To the extent any information in utilities' 
26    Multi-Year Integrated Grid Plans is designated as 
 
 
10400SB0025ham004- 681 -LRB104 16098 AAS 29398 a

1    confidential and proprietary under the Commission's rules, 
2    the proponent of the designation shall have the burden of 
3    making the requisite showing under the Commission's rules. 
4    For data that is determined to be confidential or that 
5    includes personally identifiable information, the 
6    Commission may develop procedures and processes to enable 
7    data sharing with parties and stakeholders while ensuring 
8    the confidentiality of the information. All confidential 
9    information exchanged, submitted, or shared by a utility 
10    pursuant to this Section shall be protected from 
11    intentional and accidental dissemination. The Commission 
12    shall have authority to supervise, protect, and restrict 
13    access to all confidential, commercially sensitive, or 
14    system security related information and data, and shall be 
15    authorized to take all necessary steps to protect that 
16    information from unauthorized disclosure. This paragraph 
17    shall not be interpreted to require a utility to make 
18    publicly available any information or data that could 
19    compromise the physical or cyber security of a utility's 
20    distribution system. Any party that accidentally 
21    disseminates confidential information obtained pursuant to 
22    a proceeding initiated in accordance with this Section, or 
23    is the victim of a cyber-security breach, must notify the 
24    affected utility, the Illinois Attorney General, and the 
25    Commission staff with 24 hours of knowledge of such 
26    dissemination or breach. Any party that fails to provide 
 
 
10400SB0025ham004- 682 -LRB104 16098 AAS 29398 a

1    required notification of such a breach shall be subject to 
2    remedies available to the Commission and the Illinois 
3    Attorney General.
4        (4) It is the policy of this State that holistic 
5    consideration of all related investments, planning 
6    processes, tariffs, rate design options, programs, and 
7    other utility policies and plans shall be required. To 
8    that end, the Commission shall consider, comprehensively, 
9    the impact of all related plans, tariffs, programs, and 
10    policies on the Plan and on each other, including:
11            (A) time-of-use pricing program pursuant to 
12        Section 16-107.7 of this Act, hourly pricing program 
13        pursuant to Section 16-107 of this Act, and any other 
14        time-variant or dynamic pricing program;
15            (B) distributed generation rebate pursuant to 
16        Section 16-107.6 of this Act;
17            (C) net electricity metering, pursuant to Section 
18        16-107.5 of this Act;
19            (D) energy efficiency programs pursuant to Section 
20        8-103B of this Act;
21            (E) beneficial electrification programs pursuant 
22        to Section 16-107.8 of this Act;
23            (F) Equitable Energy Upgrade Program pursuant to 
24        Section 16-111.10 of this Act;
25            (G) renewable energy programs and procurements set 
26        forth in the Illinois Power Agency Act, including, but 
 
 
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1        not limited to, those set forth in the long-term 
2        renewable resources procurement plan developed 
3        pursuant to Section 1-20 of that Act; and
4            (H) other plans, programs, and policies that are 
5        relevant to distribution grid investments, costs, 
6        planning, and other categories as requested by the 
7        Commission.
8        The Plan shall comprehensively detail the relationship 
9    between these plans, tariffs, and programs and to the 
10    electric utility's achievement of the objectives in 
11    subsection (d). The Plan shall be designed to coordinate 
12    each of these plans, programs, and tariffs with the 
13    electric utility's long-term distribution system 
14    investment planning in order to maximize the benefits of 
15    each.
16        (5) The initiating order for the initial Multi-Year 
17    Integrated Grid Plan, as well as each electric utility's 
18    subsequent Integrated Grid Plans under subsection (g), 
19    shall begin a contested proceeding as described in 
20    subsection (d) of Section 10-101.1 of this Act.
21            (A) In evaluating a utility's Plan, the Commission 
22        shall consider, at minimum, whether the Plan:
23                (1) meets the objectives of this Section;
24                (2) includes the components in paragraph (2) 
25            of subsection (f) of this Section;
26                (3) considers and incorporates, where 
 
 
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1            practicable, input from interested stakeholders, 
2            including parties and people who offer public 
3            comment without legal representation;
4                (4) considers nontraditional, including 
5            third-party owned, investment alternatives that 
6            can meet grid needs and provide additional 
7            benefits (including consumer, economic, and 
8            environmental benefits) beyond comparable, 
9            traditional utility-planned capital investments;
10                (5) equitably benefits environmental justice 
11            communities; and
12                (6) maximizes consumer, environmental, 
13            economic, and community benefits over a 10-year 
14            horizon.
15            (B) The Commission, after notice and hearing, 
16        shall modify each electric utility's Plan as necessary 
17        to comply with the objectives of this Section. The 
18        Commission may approve, or modify and approve, a Plan 
19        only if it finds that the Plan is reasonable, complies 
20        with the objectives and requirements of this Section, 
21        and reasonably incorporates input from parties. The 
22        Commission may reject each electric utility's Plan if 
23        it finds that the Plan does not comply with the 
24        objectives and requirements of this Section. If the 
25        Commission enters an order rejecting a Plan, the 
26        utility must refile a Plan within 3 months after that 
 
 
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1        order, and until the Commission approves a Plan, the 
2        utility's existing Plan will remain in effect.
3            (C) For the initial Integrated Grid Plan filings, 
4        the Commission shall enter an order approving, 
5        modifying, or rejecting the Plan no later than 
6        December 15, 2023. For subsequent Integrated Grid Plan 
7        filings, the Commission shall enter an order 
8        approving, modifying, or rejecting the Plan no later 
9        than December 15 of the year in which it was filed.
10            (D) Each electric utility shall file its proposed 
11        Initial Multi-Year Integrated Grid Plan no later than 
12        January 20, 2023. Prior to that date and following the 
13        initiating order, the Commission shall initiate a case 
14        management conference and shall take any appropriate 
15        steps to begin meaningful consideration of issues, 
16        including enabling interested parties to begin 
17        conducting discovery.
18        (6) As part of its order approving a utility's 
19    Multi-Year Integrated Grid Plan, including any 
20    modifications required, the Commission may create a 
21    subsequent implementation plan docket, or multiple 
22    implementation plan dockets, if the Commission determines 
23    that multiple dockets would be preferable, to consider a 
24    utility's detailed plan or plans, as directed in the 
25    Commission's order.
26    (g) No later than January 20, 2026 and every 4 years 
 
 
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1thereafter, each electric utility subject to this Section 
2shall file a new Multi-Year Integrated Grid Plan for the 
3subsequent 4 delivery years after the completion of the 
4then-effective Plan. Each Plan shall meet the requirements 
5described in subsection (f) of this Section, and shall be 
6preceded by a workshop process which meets the same 
7requirements described in subsection (e). If appropriate, the 
8Commission may require additional implementation dockets to 
9follow Subsequent Multi-Year Integrated Grid Plan filings.
10    (h) During the period leading to approval of the first 
11Multi-Year Integrated Grid Plan, each electric utility will 
12necessarily continue to invest in its distribution grid. Those 
13investments will be subject to a determination of prudence and 
14reasonableness consistent with Commission practice and law. 
15Any failure of such investments to conform to the Multi-Year 
16Integrated Grid Plan ultimately approved shall not imply 
17imprudence or unreasonableness.
18    (i) The Commission shall adopt rules to carry out the 
19provisions of this Section under the emergency rulemaking 
20provisions set forth in Section 5-45 of the Illinois 
21Administrative Procedure Act, and such emergency rules may be 
22effective no later than 90 days after the effective date of 
23this amendatory Act of the 102nd General Assembly.
24(Source: P.A. 102-662, eff. 9-15-21.)
 
25    (220 ILCS 5/16-107.5)
 
 
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1    Sec. 16-107.5. Net electricity metering.
2    (a) The General Assembly finds and declares that a program 
3to provide net electricity metering, as defined in this 
4Section, for eligible customers can encourage private 
5investment in renewable energy resources, stimulate economic 
6growth, enhance the continued diversification of Illinois' 
7energy resource mix, and protect the Illinois environment. 
8Further, to achieve the goals of this Act that robust options 
9for customer-site distributed generation and storage continue 
10to thrive in Illinois, the General Assembly finds that a 
11predictable transition must be ensured for customers between 
12full net metering at the retail electricity rate to the 
13distribution generation rebate described in Section 16-107.6. 
14    (b) As used in this Section: ,    
15        (i) "Community community renewable generation project" 
16    shall have the meaning set forth in Section 1-10 of the 
17    Illinois Power Agency Act. ;    
18        (ii) "Eligible eligible customer" means a retail 
19    customer that owns, hosts, or operates, including any 
20    third-party owned systems, a solar, wind, or other 
21    eligible renewable electrical generating facility or an 
22    eligible storage device that is located on the customer's 
23    premises or customer's side of the billing meter and is 
24    intended primarily to offset the customer's own current or 
25    future electrical requirements. ;    
26        (iii) "Electricity electricity provider" means an 
 
 
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1    electric utility or alternative retail electric supplier. ;    
2        (iv) "Eligible eligible renewable electrical 
3    generating facility" means a generator, which may include 
4    the colocation co-location of an energy storage system, 
5    that is interconnected under rules adopted by the 
6    Commission and is powered by solar electric energy, wind, 
7    dedicated crops grown for electricity generation, 
8    agricultural residues, untreated and unadulterated wood 
9    waste, livestock manure, anaerobic digestion of livestock 
10    or food processing waste, fuel cells or microturbines 
11    powered by renewable fuels, or hydroelectric energy. ;    
12        (v) "Net net electricity metering" (or "net metering") 
13    means the measurement, during the billing period 
14    applicable to an eligible customer, of the net amount of 
15    electricity supplied by an electricity provider to the 
16    customer or provided to the electricity provider by the 
17    customer or subscriber. ;    
18        (vi) "Subscriber subscriber" shall have the meaning as 
19    set forth in Section 1-10 of the Illinois Power Agency 
20    Act. ;    
21        (vii) "Subscription subscription" shall have the 
22    meaning set forth in Section 1-10 of the Illinois Power 
23    Agency Act. ;    
24        (viii) "Energy energy storage system" means 
25    commercially available technology that is capable of 
26    absorbing energy and storing it for a period of time for 
 
 
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1    use at a later time, including, but not limited to, 
2    electrochemical, thermal, and electromechanical 
3    technologies, and may be interconnected behind the 
4    customer's meter or interconnected behind its own meter. ; 
5    and    
6        (ix) "Future future electrical requirements" means 
7    modeled electrical requirements upon occupation of a new 
8    or vacant property, and other reasonable expectations of 
9    future electrical use, as well as, for occupied 
10    properties, a reasonable approximation of the annual load 
11    of 2 electric vehicles and, for non-electric heating 
12    customers, a reasonable approximation of the incremental 
13    electric load associated with fuel switching. The 
14    approximations shall be applied to the appropriate net 
15    metering tariff and do not need to be unique to each 
16    individual eligible customer. The utility shall submit 
17    these approximations to the Commission for review, 
18    modification, and approval.
19        (x) "Vehicle storage system" means a vehicle that when 
20    connected to an electric utility's distribution system is 
21    capable of being an energy storage system, as defined in 
22    Section 16-107.6.    
23    (c) A net metering facility shall be equipped with 
24metering equipment that can measure the flow of electricity in 
25both directions at the same rate.
26        (1) For eligible customers whose electric service has 
 
 
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1    not been declared competitive pursuant to Section 16-113 
2    of this Act as of July 1, 2011 and whose electric delivery 
3    service is provided and measured on a kilowatt-hour basis 
4    and electric supply service is not provided based on 
5    hourly pricing, this shall typically be accomplished 
6    through use of a single, bi-directional meter. If the 
7    eligible customer's existing electric revenue meter does 
8    not meet this requirement, the electricity provider shall 
9    arrange for the local electric utility or a meter service 
10    provider to install and maintain a new revenue meter at 
11    the electricity provider's expense, which may be the smart 
12    meter described by subsection (b) of Section 16-108.5 of 
13    this Act.
14        (2) For eligible customers whose electric service has 
15    not been declared competitive pursuant to Section 16-113 
16    of this Act as of July 1, 2011 and whose electric delivery 
17    service is provided and measured on a kilowatt demand 
18    basis and electric supply service is not provided based on 
19    hourly pricing, this shall typically be accomplished 
20    through use of a dual channel meter capable of measuring 
21    the flow of electricity both into and out of the 
22    customer's facility at the same rate and ratio. If such 
23    customer's existing electric revenue meter does not meet 
24    this requirement, then the electricity provider shall 
25    arrange for the local electric utility or a meter service 
26    provider to install and maintain a new revenue meter at 
 
 
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1    the electricity provider's expense, which may be the smart 
2    meter described by subsection (b) of Section 16-108.5 of 
3    this Act.
4        (3) For all other eligible customers, until such time 
5    as the local electric utility installs a smart meter, as 
6    described by subsection (b) of Section 16-108.5 of this 
7    Act, the electricity provider may arrange for the local 
8    electric utility or a meter service provider to install 
9    and maintain metering equipment capable of measuring the 
10    flow of electricity both into and out of the customer's 
11    facility at the same rate and ratio, typically through the 
12    use of a dual channel meter. If the eligible customer's 
13    existing electric revenue meter does not meet this 
14    requirement, then the costs of installing such equipment 
15    shall be paid for by the customer. 
16    (d) An electricity provider shall measure and charge or 
17credit for the net electricity supplied to eligible customers 
18or provided by eligible customers whose electric service has 
19not been declared competitive pursuant to Section 16-113 of 
20this Act as of July 1, 2011 and whose electric delivery service 
21is provided and measured on a kilowatt-hour basis and electric 
22supply service is not provided based on hourly pricing in the 
23following manner:
24        (1) If the amount of electricity used by the customer 
25    during the billing period exceeds the amount of 
26    electricity produced by the customer, the electricity 
 
 
10400SB0025ham004- 692 -LRB104 16098 AAS 29398 a

1    provider shall charge the customer for the net electricity 
2    supplied to and used by the customer as provided in 
3    subsection (e-5) of this Section.
4        (2) If the amount of electricity produced by a 
5    customer during the billing period exceeds the amount of 
6    electricity used by the customer during that billing 
7    period, the electricity provider supplying that customer 
8    shall apply a 1:1 kilowatt-hour credit to a subsequent 
9    bill for service to the customer for the net electricity 
10    supplied to the electricity provider. The electricity 
11    provider shall continue to carry over any excess 
12    kilowatt-hour credits earned and apply those credits to 
13    subsequent billing periods to offset any 
14    customer-generator consumption in those billing periods 
15    until all credits are used or until the end of the 
16    annualized period.
17        (3) At the end of the year or annualized over the 
18    period that service is supplied by means of net metering, 
19    or in the event that the retail customer terminates 
20    service with the electricity provider prior to the end of 
21    the year or the annualized period, any remaining credits 
22    in the customer's account shall expire.
23    (d-5) An electricity provider shall measure and charge or 
24credit for the net electricity supplied to eligible customers 
25or provided by eligible customers whose electric service has 
26not been declared competitive pursuant to Section 16-113 of 
 
 
10400SB0025ham004- 693 -LRB104 16098 AAS 29398 a

1this Act as of July 1, 2011 and whose electric delivery service 
2is provided and measured on a kilowatt-hour basis and electric 
3supply service is provided based on hourly pricing or 
4time-of-use rates in the following manner:
5        (1) If the amount of electricity used by the customer 
6    during any hourly period or time-of-use period exceeds the 
7    amount of electricity produced by the customer, the 
8    electricity provider shall charge the customer for the net 
9    electricity supplied to and used by the customer according 
10    to the terms of the contract or tariff to which the same 
11    customer would be assigned to or be eligible for if the 
12    customer was not a net metering customer.
13        (2) If the amount of electricity produced by a 
14    customer during any hourly period or time-of-use period 
15    exceeds the amount of electricity used by the customer 
16    during that hourly period or time-of-use period, the 
17    energy provider shall apply a credit for the net 
18    kilowatt-hours produced in such period. The credit shall 
19    consist of an energy credit and a delivery service credit. 
20    The energy credit shall be valued at the same price per 
21    kilowatt-hour as the electric service provider would 
22    charge for kilowatt-hour energy sales during that same 
23    hourly period or time-of-use period. The delivery credit 
24    shall be equal to the net kilowatt-hours produced in such 
25    hourly period or time-of-use period times a credit that 
26    reflects all kilowatt-hour based charges in the customer's 
 
 
10400SB0025ham004- 694 -LRB104 16098 AAS 29398 a

1    electric service rate, excluding energy charges. 
2    (e) An electricity provider shall measure and charge or 
3credit for the net electricity supplied to eligible customers 
4whose electric service has not been declared competitive 
5pursuant to Section 16-113 of this Act as of July 1, 2011 and 
6whose electric delivery service is provided and measured on a 
7kilowatt demand basis and electric supply service is not 
8provided based on hourly pricing in the following manner:
9        (1) If the amount of electricity used by the customer 
10    during the billing period exceeds the amount of 
11    electricity produced by the customer, then the electricity 
12    provider shall charge the customer for the net electricity 
13    supplied to and used by the customer as provided in 
14    subsection (e-5) of this Section. The customer shall 
15    remain responsible for all taxes, fees, and utility 
16    delivery charges that would otherwise be applicable to the 
17    net amount of electricity used by the customer.
18        (2) If the amount of electricity produced by a 
19    customer during the billing period exceeds the amount of 
20    electricity used by the customer during that billing 
21    period, then the electricity provider supplying that 
22    customer shall apply a 1:1 kilowatt-hour credit that 
23    reflects the kilowatt-hour based charges in the customer's 
24    electric service rate to a subsequent bill for service to 
25    the customer for the net electricity supplied to the 
26    electricity provider. The electricity provider shall 
 
 
10400SB0025ham004- 695 -LRB104 16098 AAS 29398 a

1    continue to carry over any excess kilowatt-hour credits 
2    earned and apply those credits to subsequent billing 
3    periods to offset any customer-generator consumption in 
4    those billing periods until all credits are used or until 
5    the end of the annualized period.
6        (3) At the end of the year or annualized over the 
7    period that service is supplied by means of net metering, 
8    or in the event that the retail customer terminates 
9    service with the electricity provider prior to the end of 
10    the year or the annualized period, any remaining credits 
11    in the customer's account shall expire.
12    (e-5) An electricity provider shall provide electric 
13service to eligible customers who utilize net metering at 
14non-discriminatory rates that are identical, with respect to 
15rate structure, retail rate components, and any monthly 
16charges, to the rates that the customer would be charged if not 
17a net metering customer. An electricity provider shall not 
18charge net metering customers any fee or charge or require 
19additional equipment, insurance, or any other requirements not 
20specifically authorized by interconnection standards 
21authorized by the Commission, unless the fee, charge, or other 
22requirement would apply to other similarly situated customers 
23who are not net metering customers. The customer will remain 
24responsible for all taxes, fees, and utility delivery charges 
25that would otherwise be applicable to the net amount of 
26electricity used by the customer. Subsections (c) through (e) 
 
 
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1of this Section shall not be construed to prevent an 
2arms-length agreement between an electricity provider and an 
3eligible customer that sets forth different prices, terms, and 
4conditions for the provision of net metering service, 
5including, but not limited to, the provision of the 
6appropriate metering equipment for non-residential customers.
7    (f) Notwithstanding the requirements of subsections (c) 
8through (e-5) of this Section, an electricity provider must 
9require dual-channel metering for customers operating eligible 
10renewable electrical generating facilities to whom the 
11provisions of neither subsection (d), (d-5), nor (e) of this 
12Section apply. In such cases, electricity charges and credits 
13shall be determined as follows: 
14        (1) The electricity provider shall assess and the 
15    customer remains responsible for all taxes, fees, and 
16    utility delivery charges that would otherwise be 
17    applicable to the gross amount of kilowatt-hours supplied 
18    to the eligible customer by the electricity provider.
19        (2) Each month that service is supplied by means of 
20    dual-channel metering, the electricity provider shall 
21    compensate the eligible customer for any excess 
22    kilowatt-hour credits at the electricity provider's 
23    avoided cost of electricity supply over the monthly period 
24    or as otherwise specified by the terms of a power-purchase 
25    agreement negotiated between the customer and electricity 
26    provider.
 
 
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1        (3) For all eligible net metering customers taking 
2    service from an electricity provider under contracts or 
3    tariffs employing hourly or time-of-use rates, any monthly 
4    consumption of electricity shall be calculated according 
5    to the terms of the contract or tariff to which the same 
6    customer would be assigned to or be eligible for if the 
7    customer was not a net metering customer. When those same 
8    customer-generators are net generators during any discrete 
9    hourly or time-of-use period, the net kilowatt-hours 
10    produced shall be valued at the same price per 
11    kilowatt-hour as the electric service provider would 
12    charge for retail kilowatt-hour sales during that same 
13    time-of-use period. 
14    (g) For purposes of federal and State laws providing 
15renewable energy credits or greenhouse gas credits, the 
16eligible customer shall be treated as owning and having title 
17to the renewable energy attributes, renewable energy credits, 
18and greenhouse gas emission credits related to any electricity 
19produced by the qualified generating unit. The electricity 
20provider may not condition participation in a net metering 
21program on the signing over of a customer's renewable energy 
22credits; provided, however, this subsection (g) shall not be 
23construed to prevent an arms-length agreement between an 
24electricity provider and an eligible customer that sets forth 
25the ownership or title of the credits.
26    (h) Within 120 days after the effective date of this 
 
 
10400SB0025ham004- 698 -LRB104 16098 AAS 29398 a

1amendatory Act of the 95th General Assembly, the Commission 
2shall establish standards for net metering and, if the 
3Commission has not already acted on its own initiative, 
4standards for the interconnection of eligible renewable 
5generating equipment to the utility system. The 
6interconnection standards shall address any procedural 
7barriers, delays, and administrative costs associated with the 
8interconnection of customer-generation while ensuring the 
9safety and reliability of the units and the electric utility 
10system. The Commission shall consider the Institute of 
11Electrical and Electronics Engineers (IEEE) Standard 1547 and 
12the issues of (i) reasonable and fair fees and costs, (ii) 
13clear timelines for major milestones in the interconnection 
14process, (iii) nondiscriminatory terms of agreement, and (iv) 
15any best practices for interconnection of distributed 
16generation.
17    (h-5) Within 90 days after the effective date of this 
18amendatory Act of the 102nd General Assembly, the Commission 
19shall: 
20        (1) establish an Interconnection Working Group. The 
21    working group shall include representatives from electric 
22    utilities, developers of renewable electric generating 
23    facilities, other industries that regularly apply for 
24    interconnection with the electric utilities, 
25    representatives of distributed generation customers, the 
26    Commission Staff, and such other stakeholders with a 
 
 
10400SB0025ham004- 699 -LRB104 16098 AAS 29398 a

1    substantial interest in the topics addressed by the 
2    Interconnection Working Group. The Interconnection Working 
3    Group shall address at least the following issues:
4            (A) cost and best available technology for 
5        interconnection and metering, including the 
6        standardization and publication of standard costs;
7            (B) transparency, accuracy and use of the 
8        distribution interconnection queue and hosting 
9        capacity maps;
10            (C) distribution system upgrade cost avoidance 
11        through use of advanced inverter functions;
12            (D) predictability of the queue management process 
13        and enforcement of timelines;
14            (E) benefits and challenges associated with group 
15        studies and cost sharing;
16            (F) minimum requirements for application to the 
17        interconnection process and throughout the 
18        interconnection process to avoid queue clogging 
19        behavior;
20            (G) process and customer service for 
21        interconnecting customers adopting distributed energy 
22        resources, including energy storage;
23            (H) options for metering distributed energy 
24        resources, including energy storage;
25            (I) interconnection of new technologies, including 
26        smart inverters and energy storage;
 
 
10400SB0025ham004- 700 -LRB104 16098 AAS 29398 a

1            (J) collect, share, and examine data on Level 1 
2        interconnection costs, including cost and type of 
3        upgrades required for interconnection, and use this 
4        data to inform the final standardized cost of Level 1 
5        interconnection; and
6            (K) such other technical, policy, and tariff 
7        issues related to and affecting interconnection 
8        performance and customer service as determined by the 
9        Interconnection Working Group. 
10        The Commission may create subcommittees of the 
11    Interconnection Working Group to focus on specific issues 
12    of importance, as appropriate. The Interconnection Working 
13    Group shall report to the Commission on recommended 
14    improvements to interconnection rules and tariffs and 
15    policies as determined by the Interconnection Working 
16    Group at least every 6 months. Such reports shall include 
17    consensus recommendations of the Interconnection Working 
18    Group and, if applicable, additional recommendations for 
19    which consensus was not reached. The Commission shall use 
20    the report from the Interconnection Working Group to 
21    determine whether processes should be commenced to 
22    formally codify or implement the recommendations;
23        (2) create or contract for an Ombudsman to resolve 
24    interconnection disputes through non-binding arbitration. 
25    The Ombudsman may be paid in full or in part through fees 
26    levied on the initiators of the dispute; and
 
 
10400SB0025ham004- 701 -LRB104 16098 AAS 29398 a

1        (3) determine a single standardized cost for Level 1 
2    interconnections, which shall not exceed $200. 
3    (i) All electricity providers shall begin to offer net 
4metering no later than April 1, 2008.
5    (j) An electricity provider shall provide net metering to 
6eligible customers according to subsections (d), (d-5), and 
7(e). Eligible renewable electrical generating facilities for 
8which eligible customers registered for net metering before 
9January 1, 2025 shall continue to receive net metering 
10services according to subsections (d), (d-5), and (e) of this 
11Section for the lifetime of the system, regardless of whether 
12those retail customers change electricity providers or whether 
13the retail customer benefiting from the system changes. On and 
14after January 1, 2025, any eligible customer that applies for 
15net metering and previously would have qualified under 
16subsections (d), (d-5), or (e) shall only be eligible for net 
17metering as described in subsection (n). 
18    (k) Each electricity provider shall maintain records and 
19report annually to the Commission the total number of net 
20metering customers served by the provider, as well as the 
21type, capacity, and energy sources of the generating systems 
22used by the net metering customers. Nothing in this Section 
23shall limit the ability of an electricity provider to request 
24the redaction of information deemed by the Commission to be 
25confidential business information.
26    (l)(1) Notwithstanding the definition of "eligible 
 
 
10400SB0025ham004- 702 -LRB104 16098 AAS 29398 a

1customer" in item (ii) of subsection (b) of this Section, each 
2electricity provider shall allow net metering as set forth in 
3this subsection (l) and for the following projects, provided 
4that only electric utilities serving more than 200,000 
5customers as of January 1, 2021 shall provide net metering for 
6projects that are eligible for subparagraph (C) of this 
7paragraph (1) and have energized after the effective date of 
8this amendatory Act of the 102nd General Assembly: 
9        (A) properties owned or leased by multiple customers 
10    that contribute to the operation of an eligible renewable 
11    electrical generating facility through an ownership or 
12    leasehold interest of at least 200 watts in such facility, 
13    such as a community-owned wind project, a community-owned 
14    biomass project, a community-owned solar project, or a 
15    community methane digester processing livestock waste from 
16    multiple sources, provided that the facility is also 
17    located within the utility's service territory; 
18        (B) individual units, apartments, or properties 
19    located in a single building that are owned or leased by 
20    multiple customers and collectively served by a common 
21    eligible renewable electrical generating facility, such as 
22    an office or apartment building, a shopping center or 
23    strip mall served by photovoltaic panels on the roof; and 
24        (C) subscriptions to community renewable generation 
25    projects, including community renewable generation 
26    projects on the customer's side of the billing meter of a 
 
 
10400SB0025ham004- 703 -LRB104 16098 AAS 29398 a

1    host facility and partially used for the customer's own 
2    load.
3    In addition, the nameplate capacity of the eligible 
4renewable electric generating facility that serves the demand 
5of the properties, units, or apartments identified in 
6paragraphs (1) and (2) of this subsection (l) shall not exceed 
75,000 kilowatts in nameplate capacity in total. Any eligible 
8renewable electrical generating facility or community 
9renewable generation project that is powered by photovoltaic 
10electric energy and installed after the effective date of this 
11amendatory Act of the 99th General Assembly must be installed 
12by a qualified person in compliance with the requirements of 
13Section 16-128A of the Public Utilities Act and any rules or 
14regulations adopted thereunder.
15    (2) Notwithstanding anything to the contrary, an 
16electricity provider shall provide credits for the electricity 
17produced by the projects described in paragraph (1) of this 
18subsection (l). The electricity provider shall provide credits 
19that include at least energy supply, capacity, transmission, 
20and, if applicable, the purchased energy adjustment on the 
21subscriber's monthly bill equal to the subscriber's share of 
22the production of electricity from the project, as determined 
23by paragraph (3) of this subsection (l). For customers with 
24transmission or capacity charges not charged on a 
25kilowatt-hour basis, the electricity provider shall prepare a 
26reasonable approximation of the kilowatt-hour equivalent value 
 
 
10400SB0025ham004- 704 -LRB104 16098 AAS 29398 a

1and provide that value as a monetary credit. The electricity 
2provider shall submit these approximation methodologies to the 
3Commission for review, modification, and approval. 
4Notwithstanding anything to the contrary, customers on payment 
5plans or participating in budget billing programs shall have 
6credits applied on a monthly basis. 
7    (3) Notwithstanding anything to the contrary and 
8regardless of whether a subscriber to an eligible community 
9renewable generation project receives power and energy service 
10from the electric utility or an alternative retail electric 
11supplier, for projects eligible under paragraph (C) of 
12subparagraph (1) of this subsection (l), electric utilities 
13serving more than 200,000 customers as of January 1, 2021 
14shall provide the monetary credits to a subscriber's 
15subsequent bill for the electricity produced by community 
16renewable generation projects. The electric utility shall 
17provide monetary credits to a subscriber's subsequent bill at 
18the utility's total price to compare equal to the subscriber's 
19share of the production of electricity from the project, as 
20determined by paragraph (5) of this subsection (l). For the 
21purposes of this subsection, "total price to compare" means 
22the rate or rates published by the Illinois Commerce 
23Commission for energy supply for eligible customers receiving 
24supply service from the electric utility, and shall include 
25energy, capacity, transmission, and the purchased energy 
26adjustment. Notwithstanding anything to the contrary, 
 
 
10400SB0025ham004- 705 -LRB104 16098 AAS 29398 a

1customers on payment plans or participating in budget billing 
2programs shall have credits applied on a monthly basis. Any 
3applicable credit or reduction in load obligation from the 
4production of the community renewable generating projects 
5receiving a credit under this subsection shall be credited to 
6the electric utility to offset the cost of providing the 
7credit. To the extent that the credit or load obligation 
8reduction does not completely offset the cost of providing the 
9credit to subscribers of community renewable generation 
10projects as described in this subsection, the electric utility 
11may recover the remaining costs through its Multi-Year Rate 
12Plan. All electric utilities serving 200,000 or fewer 
13customers as of January 1, 2021 shall only provide the 
14monetary credits to a subscriber's subsequent bill for the 
15electricity produced by community renewable generation 
16projects if the subscriber receives power and energy service 
17from the electric utility. Alternative retail electric 
18suppliers providing power and energy service to a subscriber 
19located within the service territory of an electric utility 
20not subject to Sections 16-108.18 and 16-118 shall provide the 
21monetary credits to the subscriber's subsequent bill for the 
22electricity produced by community renewable generation 
23projects.
24    (4) If requested by the owner or operator of a community 
25renewable generating project, an electric utility serving more 
26than 200,000 customers as of January 1, 2021 shall enter into a 
 
 
10400SB0025ham004- 706 -LRB104 16098 AAS 29398 a

1net crediting agreement with the owner or operator to include 
2a subscriber's subscription fee on the subscriber's monthly 
3electric bill and provide the subscriber with a net credit 
4equivalent to the total bill credit value for that generation 
5period minus the subscription fee, provided the subscription 
6fee is structured as a fixed percentage of bill credit value. 
7The net crediting agreement shall set forth payment terms from 
8the electric utility to the owner or operator of the community 
9renewable generating project, and the electric utility may 
10charge a net crediting fee to the owner or operator of a 
11community renewable generating project that may not exceed 1%    
122% of the subscription fee bill credit value. Notwithstanding 
13anything to the contrary, an electric utility serving 200,000 
14customers or fewer as of January 1, 2021 shall not be obligated 
15to enter into a net crediting agreement with the owner or 
16operator of a community renewable generating project. An 
17electric utility shall use the same net crediting format for 
18subscribers on payment plans and subscribers participating in 
19budget billing programs. For the purposes of this paragraph 
20(4), "net crediting" means a program offered by an electric 
21utility under which the electric utility, upon authorization 
22by or on behalf of a subscriber, remits the cash value of the 
23subscription fee to the owner or operator of the community 
24renewable generation facility without regard to whether the 
25subscriber has paid the subscriber's monthly electric bill and 
26places the cash value of the remaining bill credit on the 
 
 
10400SB0025ham004- 707 -LRB104 16098 AAS 29398 a

1subscriber's bill.    
2    (5) For the purposes of facilitating net metering, the 
3owner or operator of the eligible renewable electrical 
4generating facility or community renewable generation project 
5shall be responsible for determining the amount of the credit 
6that each customer or subscriber participating in a project 
7under this subsection (l) is to receive in the following 
8manner: 
9        (A) The owner or operator shall, on a monthly basis, 
10    provide to the electric utility the kilowatthours of 
11    generation attributable to each of the utility's retail 
12    customers and subscribers participating in projects under 
13    this subsection (l) in accordance with the customer's or 
14    subscriber's share of the eligible renewable electric 
15    generating facility's or community renewable generation 
16    project's output of power and energy for such month. The 
17    owner or operator shall electronically transmit such 
18    calculations and associated documentation to the electric 
19    utility, in a format or method set forth in the applicable 
20    tariff, on a monthly basis so that the electric utility 
21    can reflect the monetary credits on customers' and 
22    subscribers' electric utility bills. The electric utility 
23    shall be permitted to revise its tariffs to implement the 
24    provisions of this amendatory Act of the 102nd General 
25    Assembly. The owner or operator shall separately provide 
26    the electric utility with the documentation detailing the 
 
 
10400SB0025ham004- 708 -LRB104 16098 AAS 29398 a

1    calculations supporting the credit in the manner set forth 
2    in the applicable tariff. 
3        (B) For those participating customers and subscribers 
4    who receive their energy supply from an alternative retail 
5    electric supplier, the electric utility shall remit to the 
6    applicable alternative retail electric supplier the 
7    information provided under subparagraph (A) of this 
8    paragraph (3) for such customers and subscribers in a 
9    manner set forth in such alternative retail electric 
10    supplier's net metering program, or as otherwise agreed 
11    between the utility and the alternative retail electric 
12    supplier. The alternative retail electric supplier shall 
13    then submit to the utility the amount of the charges for 
14    power and energy to be applied to such customers and 
15    subscribers, including the amount of the credit associated 
16    with net metering. 
17        (C) A participating customer or subscriber may provide 
18    authorization as required by applicable law that directs 
19    the electric utility to submit information to the owner or 
20    operator of the eligible renewable electrical generating 
21    facility or community renewable generation project to 
22    which the customer or subscriber has an ownership or 
23    leasehold interest or a subscription. Such information 
24    shall be limited to the components of the net metering 
25    credit calculated under this subsection (l), including the 
26    bill credit rate, total kilowatthours, and total monetary 
 
 
10400SB0025ham004- 709 -LRB104 16098 AAS 29398 a

1    credit value applied to the customer's or subscriber's 
2    bill for the monthly billing period. 
3    (l-5) Within 90 days after the effective date of this 
4amendatory Act of the 102nd General Assembly, each electric 
5utility subject to this Section shall file a tariff or tariffs 
6to implement the provisions of subsection (l) of this Section, 
7which shall, consistent with the provisions of subsection (l), 
8describe the terms and conditions under which owners or 
9operators of qualifying properties, units, or apartments may 
10participate in net metering. The Commission shall approve, or 
11approve with modification, the tariff within 120 days after 
12the effective date of this amendatory Act of the 102nd General 
13Assembly. 
14    (l-10) Within 30 days after the effective date of this 
15amendatory Act of the 104th General Assembly, each electricity 
16provider shall modify its tariffs to allow net metering as set 
17forth in this subsection for an energy storage system or 
18vehicle storage system energized after the effective date of 
19this amendatory Act of the 104th General Assembly with a 
20nameplate capacity of not more than 5,000 kilowatts. If the 
21Commission chooses to suspend the modified tariffs, the 
22Commission shall issue a final order approving, or approving 
23with modification, the modified tariffs no later than 90 days 
24after the Commission initiates the docket.    
25    An energy storage system or vehicle storage system 
26eligible for net metering under this subsection may be 
 
 
10400SB0025ham004- 710 -LRB104 16098 AAS 29398 a

1interconnected behind the meter of a retail customer or at the 
2distribution system level of an electric utility as follows:
3        (A) if the energy storage system or vehicle storage 
4    system is interconnected behind the meter of a retail 
5    customer, in order to receive net metering under this 
6    subsection, the eligible customer behind whose meter the 
7    energy storage system is interconnected must receive 
8    service from an electricity provider under an hourly 
9    supply tariff, a time-of-use supply tariff, or a 
10    time-of-use contract with an alternative retail electric 
11    supplier; or
12        (B) if the energy storage system or vehicle storage 
13    system is interconnected at the distribution system level 
14    of an electric utility and not behind the meter of a retail 
15    customer, the energy storage system or vehicle storage 
16    system must receive service from an electricity provider 
17    as a retail customer under an hourly supply tariff 
18    authorized by Section 16-107, a supply tariff or contract 
19    on substantially similar terms and conditions with an 
20    alternative retail electric supplier, a time-of-use supply 
21    tariff, or a time-of-use supply contract with an 
22    alternative retail electric supplier.
23    If the energy storage system or vehicle storage system is 
24interconnected behind the meter of an eligible customer, the 
25eligible customer shall receive net metering based on hourly 
26or time-of-use rates in accordance with the terms of 
 
 
10400SB0025ham004- 711 -LRB104 16098 AAS 29398 a

1subsection (d-5) or (f) or paragraph (2) of subsection (n) of 
2this Section, as applicable to the eligible customer. If the 
3energy storage system or vehicle storage system is 
4interconnected at the distribution system level of an electric 
5utility and not behind the meter of a retail customer, then the 
6energy storage system or vehicle storage system shall receive 
7net metering pursuant to the terms of subsection (f) of this 
8Section.    
9    (m) Nothing in this Section shall affect the right of an 
10electricity provider to continue to provide, or the right of a 
11retail customer to continue to receive service pursuant to a 
12contract for electric service between the electricity provider 
13and the retail customer in accordance with the prices, terms, 
14and conditions provided for in that contract. Either the 
15electricity provider or the customer may require compliance 
16with the prices, terms, and conditions of the contract. 
17    (n) On and after January 1, 2025, the net metering 
18services described in subsections (d), (d-5), and (e) of this 
19Section shall no longer be offered, except as to those 
20eligible renewable electrical generating facilities for which 
21retail customers are receiving net metering service under 
22these subsections at the time the net metering services under 
23those subsections are no longer offered; those systems shall 
24continue to receive net metering services described in 
25subsections (d), (d-5), and (e) of this Section for the 
26lifetime of the system, regardless of if those retail 
 
 
10400SB0025ham004- 712 -LRB104 16098 AAS 29398 a

1customers change electricity providers or whether the retail 
2customer benefiting from the system changes. The electric 
3utility serving more than 200,000 customers as of January 1, 
42021 is responsible for ensuring the billing credits continue 
5without lapse for the lifetime of systems, as required in 
6subsection (o). Those retail customers that begin taking net 
7metering service after the date that net metering services are 
8no longer offered under such subsections shall be subject to 
9the provisions set forth in the following paragraphs (1) 
10through (3) of this subsection (n):
11        (1) An electricity provider shall charge or credit for 
12    the net electricity supplied to eligible customers or 
13    provided by eligible customers whose electric supply 
14    service is not provided based on hourly pricing in the 
15    following manner:
16            (A) If the amount of electricity used by the 
17        customer during the monthly billing period exceeds the 
18        amount of electricity produced by the customer, then 
19        the electricity provider shall charge the customer for 
20        the net kilowatt-hour based electricity charges 
21        reflected in the customer's electric service rate 
22        supplied to and used by the customer as provided in 
23        paragraph (3) of this subsection (n).
24            (B) If the amount of electricity produced by a 
25        customer during the monthly billing period exceeds the 
26        amount of electricity used by the customer during that 
 
 
10400SB0025ham004- 713 -LRB104 16098 AAS 29398 a

1        billing period, then the electricity provider 
2        supplying that customer shall apply a 1:1 
3        kilowatt-hour energy or monetary credit kilowatt-hour 
4        supply charges to the customer's subsequent bill. The 
5        customer shall choose between 1:1 kilowatt-hour or 
6        monetary credit at the time of application. For the 
7        purposes of this subsection, "kilowatt-hour supply 
8        charges" means the kilowatt-hour equivalent values for 
9        energy, capacity, transmission, and the purchased 
10        energy adjustment, if applicable. Notwithstanding 
11        anything to the contrary, customers on payment plans 
12        or participating in budget billing programs shall have 
13        credits applied on a monthly basis. The electricity 
14        provider shall continue to carry over any excess 
15        kilowatt-hour or monetary energy credits earned and 
16        apply those credits to subsequent billing periods. For 
17        customers with transmission or capacity charges not 
18        charged on a kilowatt-hour basis, the electricity 
19        provider shall prepare a reasonable approximation of 
20        the kilowatt-hour equivalent value and provide that 
21        value as a monetary credit. The electricity provider 
22        shall submit these approximation methodologies to the 
23        Commission for review, modification, and approval.
24            (C) (Blank).
25        (2) An electricity provider shall charge or credit for 
26    the net electricity supplied to eligible customers or 
 
 
10400SB0025ham004- 714 -LRB104 16098 AAS 29398 a

1    provided by eligible customers whose electric supply 
2    service is provided based on hourly pricing in the 
3    following manner:
4            (A) If the amount of electricity used by the 
5        customer during any hourly period exceeds the amount 
6        of electricity produced by the customer, then the 
7        electricity provider shall charge the customer for the 
8        net electricity supplied to and used by the customer 
9        as provided in paragraph (3) of this subsection (n).
10            (B) If the amount of electricity produced by a 
11        customer during any hourly period exceeds the amount 
12        of electricity used by the customer during that hourly 
13        period, the energy provider shall calculate an energy 
14        credit for the net kilowatt-hours produced in such 
15        period, and shall apply that credit as a monetary 
16        credit to the customer's subsequent bill. The value of 
17        the energy credit shall be calculated using the same 
18        price per kilowatt-hour as the electric service 
19        provider would charge for kilowatt-hour energy sales 
20        during that same hourly period and shall also include 
21        values for capacity and transmission. For customers 
22        with transmission or capacity charges not charged on a 
23        kilowatt-hour basis, the electricity provider shall 
24        prepare a reasonable approximation of the 
25        kilowatt-hour equivalent value and provide that value 
26        as a monetary credit. The electricity provider shall 
 
 
10400SB0025ham004- 715 -LRB104 16098 AAS 29398 a

1        submit these approximation methodologies to the 
2        Commission for review, modification, and approval. 
3        Notwithstanding anything to the contrary, customers on 
4        payment plans or participating in budget billing 
5        programs shall have credits applied on a monthly 
6        basis. 
7        (3) An electricity provider shall provide electric 
8    service to eligible customers who utilize net metering at 
9    non-discriminatory rates that are identical, with respect 
10    to rate structure, retail rate components, and any monthly 
11    charges, to the rates that the customer would be charged 
12    if not a net metering customer. An electricity provider 
13    shall charge the customer for the net electricity supplied 
14    to and used by the customer according to the terms of the 
15    contract or tariff to which the same customer would be 
16    assigned or be eligible for if the customer was not a net 
17    metering customer. An electricity provider shall not 
18    charge net metering customers any fee or charge or require 
19    additional equipment, insurance, or any other requirements 
20    not specifically authorized by interconnection standards 
21    authorized by the Commission, unless the fee, charge, or 
22    other requirement would apply to other similarly situated 
23    customers who are not net metering customers. The customer 
24    remains responsible for the gross amount of delivery 
25    services charges, supply-related charges that are kilowatt 
26    based, and all taxes and fees related to such charges. The 
 
 
10400SB0025ham004- 716 -LRB104 16098 AAS 29398 a

1    customer also remains responsible for all taxes and fees 
2    that would otherwise be applicable to the net amount of 
3    electricity used by the customer. Paragraphs (1) and (2) 
4    of this subsection (n) shall not be construed to prevent 
5    an arms-length agreement between an electricity provider 
6    and an eligible customer that sets forth different prices, 
7    terms, and conditions for the provision of net metering 
8    service, including, but not limited to, the provision of 
9    the appropriate metering equipment for non-residential 
10    customers. Nothing in this paragraph (3) shall be 
11    interpreted to mandate that a utility that is only 
12    required to provide delivery services to a given customer 
13    must also sell electricity to such customer. 
14    (o) Within 90 days after the effective date of this 
15amendatory Act of the 102nd General Assembly, each electric 
16utility subject to this Section shall file a tariff, which 
17shall, consistent with the provisions of this Section, propose 
18the terms and conditions under which a customer may 
19participate in net metering. The tariff for electric utilities 
20serving more than 200,000 customers as of January 1, 2021 
21shall also provide a streamlined and transparent bill 
22crediting system for net metering to be managed by the 
23electric utilities. The terms and conditions shall include, 
24but are not limited to, that an electric utility shall manage 
25and maintain billing of net metering credits and charges 
26regardless of if the eligible customer takes net metering 
 
 
10400SB0025ham004- 717 -LRB104 16098 AAS 29398 a

1under an electric utility or alternative retail electric 
2supplier. The electric utility serving more than 200,000 
3customers as of January 1, 2021 shall process and approve all 
4net metering applications, even if an eligible customer is 
5served by an alternative retail electric supplier; and the 
6utility shall forward application approval to the appropriate 
7alternative retail electric supplier. Eligibility for net 
8metering shall remain with the owner of the utility billing 
9address such that, if an eligible renewable electrical 
10generating facility changes ownership, the net metering 
11eligibility transfers to the new owner. The electric utility 
12serving more than 200,000 customers as of January 1, 2021 
13shall manage net metering billing for eligible customers to 
14ensure full crediting occurs on electricity bills, including, 
15but not limited to, ensuring net metering crediting begins 
16upon commercial operation date, net metering billing transfers 
17immediately if an eligible customer switches from an electric 
18utility to alternative retail electric supplier or vice versa, 
19and net metering billing transfers between ownership of a 
20valid billing address. All transfers referenced in the 
21preceding sentence shall include transfer of all banked 
22credits. All electric utilities serving 200,000 or fewer 
23customers as of January 1, 2021 shall manage net metering 
24billing for eligible customers receiving power and energy 
25service from the electric utility to ensure full crediting 
26occurs on electricity bills, ensuring net metering crediting 
 
 
10400SB0025ham004- 718 -LRB104 16098 AAS 29398 a

1begins upon commercial operation date, net metering billing 
2transfers immediately if an eligible customer switches from an 
3electric utility to alternative retail electric supplier or 
4vice versa, and net metering billing transfers between 
5ownership of a valid billing address. Alternative retail 
6electric suppliers providing power and energy service to 
7eligible customers located within the service territory of an 
8electric utility serving 200,000 or fewer customers as of 
9January 1, 2021 shall manage net metering billing for eligible 
10customers to ensure full crediting occurs on electricity 
11bills, including, but not limited to, ensuring net metering 
12crediting begins upon commercial operation date, net metering 
13billing transfers immediately if an eligible customer switches 
14from an electric utility to alternative retail electric 
15supplier or vice versa, and net metering billing transfers 
16between ownership of a valid billing address. 
17(Source: P.A. 102-662, eff. 9-15-21.)
 
18    (220 ILCS 5/16-107.6)
19    Sec. 16-107.6. Distributed generation and storage rebate.
20    (a) In this Section:
21    "Additive services" means the services that distributed 
22energy resources provide to the energy system and society that 
23are described in Section 16-107.9 not (1) already included in 
24the base rebates for system-wide grid services; or (2) 
25otherwise already compensated. Additive services may reflect, 
 
 
10400SB0025ham004- 719 -LRB104 16098 AAS 29398 a

1but shall not be limited to, any geographic, time-based, 
2performance-based, and other benefits of distributed energy 
3resources, as well as the present and future technological 
4capabilities of distributed energy resources and present and 
5future grid needs. 
6    "Distributed energy resource" means a wide range of 
7technologies that are located on the customer side of the 
8customer's electric meter, including, but not limited to, 
9distributed generation, energy storage, electric vehicles, and 
10demand response technologies. 
11    "Distributed storage" means energy storage systems that 
12are interconnected behind the customer's meter to the 
13distribution system or interconnected behind the storage 
14system's own meter to the distribution system.    
15    "Energy storage system" means commercially available 
16technology that is capable of absorbing energy and storing it 
17for a period of time for use at a later time, including, but 
18not limited to, electrochemical, thermal, and 
19electromechanical technologies, and may be interconnected 
20behind the customer's meter or interconnected behind its own 
21meter. 
22    "Smart inverter" means a device that converts direct 
23current into alternating current and meets the IEEE 1547-2018 
24equipment standards. Until devices that meet the IEEE 
251547-2018 standard are available, devices that meet the UL 
261741 SA standard are acceptable.
 
 
10400SB0025ham004- 720 -LRB104 16098 AAS 29398 a

1    "Subscriber" has the meaning set forth in Section 1-10 of 
2the Illinois Power Agency Act.
3    "Subscription" has the meaning set forth in Section 1-10 
4of the Illinois Power Agency Act.
5    "System-wide grid services" means the benefits that a 
6distributed energy resource provides to the distribution grid 
7for a period of no less than 25 years. System-wide grid 
8services do not vary by location, time, or the performance 
9characteristics of the distributed energy resource. 
10System-wide grid services include, but are not limited to, 
11avoided or deferred distribution capacity costs, resilience 
12and reliability benefits, avoided or deferred distribution 
13operation and maintenance costs, distribution voltage and 
14power quality benefits, and line loss reductions. 
15    "Threshold date" means the date 2 years after the 
16effective date of this amendatory Act of the 104th General 
17Assembly December 31, 2024 or the date on which the utility's 
18tariff or tariffs authorized by Section 16-107.9 setting the 
19new compensation values established under subsection (e) take 
20effect, whichever is later.
21    (b) An electric utility that serves more than 200,000 
22customers in the State shall file a petition with the 
23Commission requesting approval of the utility's tariff to 
24provide a rebate to the owner or operator of distributed 
25generation, including third-party owned systems, that meets 
26the following criteria:
 
 
10400SB0025ham004- 721 -LRB104 16098 AAS 29398 a

1        (1) has a nameplate generating capacity, as defined in 
2    Section 1-10 of the Illinois Power Agency Act no greater 
3    than 5,000 kilowatts and is primarily used to offset a 
4    customer's electricity load;
5        (2) is located on the customer's side of the billing 
6    meter and for the customer's own use;
7        (3) is interconnected to electric distribution 
8    facilities owned by the electric utility under rules 
9    adopted by the Commission by means of one or more 
10    inverters or smart inverters required by this Section, as 
11    applicable.
12    For purposes of this Section, "distributed generation" 
13shall satisfy the definition of distributed renewable energy 
14generation device set forth in Section 1-10 of the Illinois 
15Power Agency Act to the extent such definition is consistent 
16with the requirements of this Section. 
17    In addition, any new photovoltaic distributed generation 
18that is installed after June 1, 2017 (the effective date of 
19Public Act 99-906) must be installed by a qualified person, as 
20defined by subsection (i) of Section 1-56 of the Illinois 
21Power Agency Act. 
22    The tariff shall include a base rebate that compensates 
23distributed generation for the system-wide grid services 
24associated with distributed generation and, after the 
25proceeding described in subsection (e) of this Section, an 
26additional payment or payments for any the additive services 
 
 
10400SB0025ham004- 722 -LRB104 16098 AAS 29398 a

1identified by the Commission under Section 16-107.9. The 
2distributed generation and storage tariff shall provide that 
3the smart inverter or smart inverters associated with the 
4distributed generation shall provide autonomous response to 
5grid conditions through its default settings as approved by 
6the Commission. Default settings may not be changed after the 
7execution of the interconnection agreement except by mutual 
8agreement between the utility and the owner or operator of the 
9distributed generation. Nothing in this Section shall negate 
10or supersede Institute of Electrical and Electronics Engineers 
11equipment standards or other similar standards or 
12requirements. The tariff shall not limit the ability of the 
13smart inverter or smart inverters or other distributed energy 
14resource to provide wholesale market products such as 
15regulation, demand response, or other services, or limit the 
16ability of the owner of the smart inverter or the other 
17distributed energy resource to receive compensation for 
18providing those wholesale market products or services.
19    (b-5) Within 30 days after the effective date of this 
20amendatory Act of the 102nd General Assembly, each electric 
21public utility with 3,000,000 or more retail customers shall 
22file a tariff with the Commission that further compensates any 
23retail customer that installs or has installed photovoltaic 
24facilities paired with energy storage facilities on or 
25adjacent to its premises for the benefits the facilities 
26provide to the distribution grid. The tariff shall provide 
 
 
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1that, in addition to the other rebates identified in this 
2Section, the electric utility shall rebate to such retail 
3customer (i) the previously incurred and future costs of 
4installing interconnection facilities and related 
5infrastructure to enable full participation in the PJM 
6Interconnection, LLC or its successor organization frequency 
7regulation market; and (ii) all wholesale demand charges 
8incurred after the effective date of this amendatory Act of 
9the 102nd General Assembly. The Commission shall approve, or 
10approve with modification, the tariff within 120 days after 
11the utility's filing. 
12    To be eligible for a rebate described in this subsection 
13(b-5), the owner or operator of the distributed generation 
14shall provide proof of participation in the frequency 
15regulation market. Upon providing proof of participation, the 
16retail customer shall be entitled to a rebate equal to the cost 
17of the interconnection facilities paid to ComEd, regardless of 
18whether the retail customer would have incurred the 
19interconnection costs in the absence of participating in the 
20frequency regulation market, plus the cost of software, 
21telecommunications hardware, and telemetry paid to enable 
22communication with PJM for purposes of participating in the 
23frequency regulation market. A utility providing rebates 
24described in this subsection (b-5) shall be entitled to 
25recover the costs of the rebates as provided for in subsection 
26(h) of this Section. To the extent the electric utility's 
 
 
10400SB0025ham004- 724 -LRB104 16098 AAS 29398 a

1tariff is modified to comply with this subsection (b-5), it 
2shall file a revised tariff with the Commission within 120 
3days after the effective date of this amendatory Act of the 
4104th General Assembly, and the Commission shall approve, or 
5approve with modification, the tariff within 240 days after 
6the Commission initiates the docket.    
7    (c) The proposed tariff authorized by subsection (b) of 
8this Section shall include the following participation terms 
9for rebates to be applied under this Section for distributed 
10generation that satisfies the criteria set forth in subsection 
11(b) of this Section:
12        (1) The owner or operator of distributed generation or 
13    distributed storage that services customers not eligible 
14    for net metering under subsection (d), (d-5), or (e) of 
15    Section 16-107.5 of this Act may apply for a rebate as 
16    provided for in this Section. The Until the threshold 
17    date, the value of the rebate shall be $250 per kilowatt of 
18    nameplate generating capacity, measured as nominal DC 
19    power output, of that customer's distributed generation. 
20    To the extent the distributed generation also has an 
21    associated energy storage, then until the threshold date 
22    for systems other than community renewable generation 
23    projects paired with an energy storage system, the energy 
24    storage system shall be separately compensated with a base    
25    rebate of $250 per kilowatt-hour of nameplate capacity. To 
26    the extent that a community renewable generation project 
 
 
10400SB0025ham004- 725 -LRB104 16098 AAS 29398 a

1    is paired with an energy storage system or an energy 
2    storage system that is paired with distributed generation, 
3    the energy storage system shall be separately compensated 
4    with a rebate of $250 per kilowatt-hour of nameplate 
5    capacity. A stand-alone energy storage system shall be 
6    compensated with a rebate of $250 per kilowatt-hour of 
7    nameplate capacity. Any distributed generation device that 
8    is compensated for storage in this subsection (1) after 
9    the effective date of this amendatory Act of the 104th 
10    General Assembly before the threshold date shall 
11    participate in one or more programs authorized by 
12    paragraph (1) of subsection (e). Compensation determined 
13    through the Multi-Year Integrated Grid Planning process 
14    that are designed to meet peak reduction and flexibility. 
15    After the threshold date, the value of the base rebate and 
16    additional compensation for any additive services shall be 
17    as determined by the Commission in the proceeding 
18    described in Section 16-107.9 subsection (e) of this 
19    Section, provided that the value of the base rebate for 
20    system-wide grid services shall not be lower than $250 per 
21    kilowatt of nameplate generating capacity of distributed 
22    generation or community renewable generation project. To 
23    the extent that an electric utility's tariffs are 
24    inconsistent with the requirements of this paragraph (1) 
25    as modified by this amendatory Act of the 104th General 
26    Assembly, the electric utility shall, within 60 days after 
 
 
10400SB0025ham004- 726 -LRB104 16098 AAS 29398 a

1    the effective date of this amendatory Act of the 104th 
2    General Assembly, file modified tariffs consistent with 
3    the requirements of this paragraph (1). If the Commission 
4    chooses to suspend the modified tariffs following notice 
5    and hearing, the Commission shall issue an order 
6    approving, or approving with modification, the modified 
7    tariffs no later than 90 days after the Commission 
8    initiates the docket.    
9        (2) The owner or operator of distributed generation 
10    that, before the threshold date, would have been eligible 
11    for net metering under subsection (d), (d-5), or (e) of 
12    Section 16-107.5 of this Act and that has not previously 
13    received a distributed generation rebate, may apply for a 
14    rebate as provided for in this Section. Until December 31, 
15    2029 the threshold date, the value of the base rebate 
16    shall be $300 per kilowatt of nameplate generating 
17    capacity, measured as nominal DC power output, of the 
18    distributed generation. On or after January 1, 2030, the 
19    value of the base rebate shall be $250 per kilowatt of 
20    nameplate generating capacity, measured as nominal DC 
21    power output, of the distributed generation. The owner or 
22    operator of distributed generation that, before the 
23    threshold date, is eligible for net metering under 
24    subsection (d), (d-5), or (e) of Section 16-107.5 of this 
25    Act may apply for a base rebate for an associated energy 
26    storage device behind the same retail customer meter as 
 
 
10400SB0025ham004- 727 -LRB104 16098 AAS 29398 a

1    the distributed generation, regardless of whether the 
2    distributed generation applies for a rebate for the 
3    distributed generation device. An The energy storage 
4    system, whether or not paired with distributed generation,    
5    shall be separately compensated at a base payment of $300 
6    per kilowatt-hour of nameplate capacity until the 
7    threshold date. After the threshold date, a stand-alone 
8    energy storage system shall be compensated with a rebate 
9    of $250 per kilowatt-hour of nameplate capacity. Any 
10    distributed generation device that is compensated for 
11    storage in this subsection (2) has the option to before 
12    the threshold date shall participate in either an a peak 
13    time rebate program, hourly pricing program, or 
14    time-of-use rate program and any distributed generation 
15    device that is compensated for storage in this subsection 
16    (2) after the effective date of this amendatory Act of the 
17    104th General Assembly shall participate in a scheduled 
18    dispatch program set forth in paragraph (1) of subsection 
19    (e) when it becomes available offered by the applicable 
20    electric utility. Compensation After the threshold date, 
21    the value of the base rebate and additional compensation    
22    for any additive services or other programs shall be as 
23    determined by the Commission in the proceeding described 
24    in Section 16-107.9 subsection (e) of this Section, 
25    provided that, prior to December 31, 2029, the value of 
26    the base rebate for system-wide services shall not be 
 
 
10400SB0025ham004- 728 -LRB104 16098 AAS 29398 a

1    lower than $300 per kilowatt of nameplate generating 
2    capacity of distributed generation, after which it shall 
3    not be lower than $250 per kilowatt of nameplate capacity. 
4    The eligibility of energy storage devices that are 
5    interconnected behind the same retail customer meter as 
6    the distributed generation shall not be limited to energy 
7    storage devices interconnected after the effective date of 
8    this amendatory Act of the 103rd General Assembly. To the 
9    extent that an electric utility's tariffs are inconsistent 
10    with the requirements of this paragraph (2) as modified by 
11    this amendatory Act of the 104th General Assembly this 
12    amendatory Act of the 103rd General Assembly, such 
13    electric utility shall, within 60 30 days, file modified 
14    tariffs consistent with the requirements of this paragraph 
15    (2). 
16        (3) Upon approval of a rebate application submitted 
17    under this subsection (c), the retail customer shall no 
18    longer be entitled to receive any delivery service credits 
19    for the excess electricity generated by its facility and 
20    shall be subject to the provisions of subsection (n) of 
21    Section 16-107.5 of this Act unless the owner or operator 
22    receives a rebate only for an energy storage device and 
23    not for the distributed generation device.
24        (4) To be eligible for a rebate described in this 
25    subsection (c), the owner or operator of the distributed 
26    generation must have a smart inverter installed and in 
 
 
10400SB0025ham004- 729 -LRB104 16098 AAS 29398 a

1    operation on the distributed generation.
2        (5) The owner or operator of any distributed 
3    generation or distributed storage system whose electric 
4    service has not been declared competitive under Section 
5    16-113 as of July 1, 2011 or the owner or operator of a 
6    community renewable generation project participating in 
7    the Adjustable Block Program as a community-driven 
8    community solar project as defined in item (v) of 
9    subparagraph (K) of paragraph (1) of subsection (c) of 
10    Section 1-75 of the Illinois Power Agency Act and that has 
11    an interconnection agreement dated after the effective 
12    date of this amendatory Act of the 104th General Assembly 
13    shall be eligible for an additional payment or payments to 
14    the applicable rebate under paragraphs (1) or (2) of this 
15    subsection (c) in an amount set by tariff and approved by 
16    the Commission if located in an equity investment eligible 
17    community, as defined in Section 1-10 of the Illinois 
18    Power Agency Act, at the time the interconnection 
19    agreement is signed.    
20    (d) The Commission shall review the proposed tariff 
21authorized by subsection (b) of this Section and may make 
22changes to the tariff that are consistent with this Section 
23and with the Commission's authority under Article IX of this 
24Act, subject to notice and hearing. Following notice and 
25hearing, the Commission shall issue an order approving, or 
26approving with modification, such tariff no later than 240 
 
 
10400SB0025ham004- 730 -LRB104 16098 AAS 29398 a

1days after the utility files its tariff. Upon the effective 
2date of this amendatory Act of the 102nd General Assembly, an 
3electric utility shall file a petition with the Commission to 
4amend and update any existing tariffs to comply with 
5subsections (b) and (c). 
6    (e) By no later than June 30, 2026 June 30, 2023, the 
7Commission shall establish a scheduled dispatch virtual power 
8plant program in which customers that own or operate an energy 
9storage system that receive a rebate for the distributed 
10storage portion under paragraphs (1) and (2) of subsection (c) 
11are required to participate open an independent, statewide 
12investigation into the value of, and compensation for, 
13distributed energy resources. The Commission shall conduct the 
14investigation, but may arrange for experts or consultants 
15independent of the utilities and selected by the Commission to 
16assist with the investigation. The cost of the investigation 
17shall be shared by the utilities filing tariffs under 
18subsection (b) of this Section but may be recovered as an 
19expense through normal ratemaking procedures.
20        (1) The scheduled dispatch virtual power plant program 
21    shall require an enrollment period of 5 years and require 
22    each participating system to commit to dispatch each 
23    weekday during the months of June, July, August, and 
24    September from 4 p.m. to 6 p.m. for systems interconnected 
25    behind the meter of a retail customer and from 4 p.m. to 7 
26    p.m. for systems interconnected on the distribution system 
 
 
10400SB0025ham004- 731 -LRB104 16098 AAS 29398 a

1    of an electric utility and not behind the meter of a retail 
2    customer. For stand-alone storage, commitments to dispatch 
3    shall be voluntary. Upon petition by the applicable 
4    electric utility or on its own motion, the Commission may 
5    approve different dispatch schedules provided that 
6    dispatch events do not exceed 80 days and shall not exceed 
7    2 hours for systems interconnected behind the meter of a 
8    retail customer or 3 hours for systems interconnected on 
9    the distribution system of an electric utility and not 
10    behind the meter of a retail customer. The Commission 
11    shall ensure that the investigation includes, at minimum, 
12    diverse sets of stakeholders; a review of best practices 
13    in calculating the value of distributed energy resource 
14    benefits; a review of the full value of the distributed 
15    energy resources and the manner in which each component of 
16    that value is or is not otherwise compensated; and 
17    assessments of how the value of distributed energy 
18    resources may evolve based on the present and future 
19    technological capabilities of distributed energy resources 
20    and based on present and future grid needs.    
21        (2) The scheduled dispatch virtual power plant program 
22    shall be open to all customer classes with eligible 
23    distributed energy resources and shall measure performance 
24    based on combined export of paired resources if the 
25    eligible device is inverter-based renewables paired with 
26    storage through at least December 31, 2030 and until the 
 
 
10400SB0025ham004- 732 -LRB104 16098 AAS 29398 a

1    Commission approves and the utility implements a tariff 
2    under subsection (d) of Section 16-107.9 of this Act, at 
3    which time such customers shall be transitioned to that 
4    tariff in a manner prescribed in the tariff. The scheduled 
5    dispatch virtual power plant program shall be required for 
6    all community renewable generation projects paired with 
7    distributed energy resources without regard to the 
8    threshold date. The Commission's final order concluding 
9    this investigation shall establish an annual process and 
10    formula for the compensation of distributed generation and 
11    energy storage systems, and an initial set of inputs for 
12    that formula. The Commission's final order concluding this 
13    investigation shall establish base rebates that compensate 
14    distributed generation, community renewable generation 
15    projects and energy storage systems for the system-wide 
16    grid services that they provide. Those base rebate values 
17    shall be consistent across the state, and shall not vary 
18    by customer, customer class, customer location, or any 
19    other variable. With respect to rebates for distributed 
20    generation or community renewable generation projects, 
21    that rebate shall not be lower than $250 per kilowatt of 
22    nameplate generating capacity of the distributed 
23    generation or community renewable generation project. The 
24    Commission's final order concluding this proceeding shall 
25    also direct the utilities to update the formula, on an 
26    annual basis, with inputs derived from their integrated 
 
 
10400SB0025ham004- 733 -LRB104 16098 AAS 29398 a

1    grid plans developed pursuant to Section 16-105.17. The 
2    base rebate shall be updated annually based on the annual 
3    updates to the formula inputs, but, with respect to 
4    rebates for distributed generation or community renewable 
5    generation projects, shall be no lower than $250 per 
6    kilowatt of nameplate generating capacity of the 
7    distributed generation or community renewable generation 
8    project.
9        (3) Compensation shall be set by the Commission but 
10    shall not be less than $10 per kilowatt of average 
11    dispatch during identified hours, paid to enrolled 
12    customers or project owners at end of program year. For 
13    distributed generation interconnected to an electric 
14    utility's distribution system and not behind the meter of 
15    a retail customer, dispatch to determine compensation 
16    shall be measured at point of interconnection. For 
17    distributed generation and storage interconnected behind 
18    the meter of a retail customer, dispatch to determine 
19    compensation shall be measured at the inverter connected 
20    to the storage device. The Commission shall also 
21    determine, as a part of its investigation under this 
22    subsection, whether distributed energy resources can 
23    provide any additive services. Those additive services may 
24    include services that are provided through 
25    utility-controlled responses to grid conditions. If the 
26    Commission determines that distributed energy resources 
 
 
10400SB0025ham004- 734 -LRB104 16098 AAS 29398 a

1    can provide additive grid services, the Commission shall 
2    determine the terms and conditions for the operation and 
3    compensation of those services. That compensation shall be 
4    above and beyond the base rebate that the distributed 
5    energy generation, community renewable generation project 
6    and energy storage system receives. Compensation for 
7    additive services may vary by location, time, performance 
8    characteristics, technology types, or other variables.
9        (4) No later than June 1, 2026, each public utility 
10    shall file an initial scheduled dispatch virtual power 
11    plant tariff. The Commission shall approve, or approve 
12    with modifications, the initial scheduled dispatch virtual 
13    power plant tariff for each utility not later than June 
14    30, 2026. The Commission shall ensure that compensation 
15    for distributed energy resources, including base rebates 
16    and any payments for additive services, shall reflect all 
17    reasonably known and measurable values of the distributed 
18    generation over its full expected useful life. 
19    Compensation for additive services shall reflect, but 
20    shall not be limited to, any geographic, time-based, 
21    performance-based, and other benefits of distributed 
22    generation, as well as the present and future 
23    technological capabilities of distributed energy resources 
24    and present and future grid needs.
25        (5) The Commission, by its own motion or by petition 
26    by an electric utility, may establish other additive 
 
 
10400SB0025ham004- 735 -LRB104 16098 AAS 29398 a

1    services programs in addition to the virtual power plant 
2    program under Section 16-107.9. Nothing in this Section is 
3    intended to preempt or delay the implementation of other 
4    utility programs for devices that are not a part of the 
5    scheduled dispatch virtual power plant program that the 
6    Commission or utility may propose or require. The 
7    Commission shall consider the electric utility's 
8    integrated grid plan developed pursuant to Section 
9    16-105.17 of this Act to help identify the value of 
10    distributed energy resources for the purpose of 
11    calculating the compensation described in this subsection.    
12        (6) No later than December 31, 2028, the utilities 
13    shall file with the Commission a report that includes 
14    information on the following: (A) the number of 
15    participants in the scheduled dispatch program; (B) 
16    impacts to energy supply prices and wholesale market 
17    activities; (C) impacts on distribution system investments 
18    and planning; and (D) any potential pathways by which the 
19    virtual power plan program described in Section 16-107.9 
20    may be designed to capture wholesale market value through 
21    participation in the wholesale market and apply that 
22    wholesale market revenue to reduce utility distribution or 
23    electric supply rates for customers. The Commission shall 
24    determine additional compensation for distributed energy 
25    resources that creates savings and value on the 
26    distribution system by being co-located or in close 
 
 
10400SB0025ham004- 736 -LRB104 16098 AAS 29398 a

1    proximity to electric vehicle charging infrastructure in 
2    use by medium-duty and heavy-duty vehicles, primarily 
3    serving environmental justice communities, as outlined in 
4    the utility integrated grid planning process under Section 
5    16-105.17 of this Act.    
6    No later than 60 days after the Commission enters its 
7final order under this subsection (e), each utility shall file 
8its updated tariff or tariffs in compliance with the order, 
9including new tariffs for the recovery of costs incurred under 
10this subsection (e) that shall provide for volumetric-based 
11cost recovery, and the Commission shall approve, or approve 
12with modification, the tariff or tariffs within 240 days after 
13the utility's filing.    
14    (f) Notwithstanding any provision of this Act to the 
15contrary, the owner or operator of a community renewable 
16generation project as defined in Section 1-10 of the Illinois 
17Power Agency Act whether or not a paired energy storage system 
18or the owner or operator of an energy storage system that is 
19eligible for net metering under subsection (l-10) of Section 
2016-107.5 shall also be eligible to apply for the rebate 
21described in this Section. The owner or operator of the 
22community renewable generation project whether or not a paired 
23energy storage system or the owner or operator of an energy 
24storage system that is eligible for net metering under 
25subsection (l-10) of Section 16-107.5 may apply for a rebate 
26only if the owner or operator, or previous owner or operator, 
 
 
10400SB0025ham004- 737 -LRB104 16098 AAS 29398 a

1of the community renewable generation project whether or not a 
2paired energy storage system or the owner or operator of an 
3energy storage system that is eligible for net metering under 
4subsection (l-10) of Section 16-107.5 has not already 
5submitted an application, and, regardless of whether the 
6subscriber is a residential or non-residential customer, may 
7be allowed the amount identified in paragraph (1) of 
8subsection (c) applicable on the date that the application is 
9submitted.
10    (g) The owner of a distributed storage system, whether or 
11not paired with distributed generation, the distributed 
12generation or community renewable generation project may apply 
13for the rebate or rebates approved under this Section at the 
14time of execution of an interconnection agreement with the 
15distribution utility and shall receive the value available at 
16that time of execution of the interconnection agreement, 
17provided the project reaches mechanical completion within 24 
18months after execution of the interconnection agreement. If 
19the project has not reached mechanical completion within 24 
20months after execution, the owner may reapply for the rebate 
21or rebates approved under this Section available at the time 
22of application and shall receive the value available at the 
23time of application. The utility shall issue the rebate no 
24later than 60 days after the project is energized. In the event 
25the application is incomplete or the utility is otherwise 
26unable to calculate the payment based on the information 
 
 
10400SB0025ham004- 738 -LRB104 16098 AAS 29398 a

1provided by the owner, the utility shall issue the payment no 
2later than 60 days after the application is complete or all 
3requested information is received.
4    (h) An electric utility shall recover from its retail 
5customers all of the costs of the rebates made under a tariff 
6or tariffs approved under subsection (d) of this Section, 
7including, but not limited to, the value of the rebates and all 
8costs incurred by the utility to comply with and implement 
9subsections (b), (b-5), and (c), and (e) of this Section, but 
10not including costs incurred by the utility to comply with and 
11implement subsection (e) of this Section, consistent with the 
12following provisions:
13        (1) The utility shall defer the full amount of its 
14    costs as a regulatory asset. The total costs deferred as a 
15    regulatory asset shall be amortized over a 15-year period. 
16    The unamortized balance shall be recognized as of December 
17    31 for a given year. The utility shall also earn a return 
18    on the total of the unamortized balance of the regulatory 
19    assets, less any deferred taxes related to the unamortized 
20    balance, at an annual rate equal to the utility's weighted 
21    average cost of capital that includes, based on a year-end 
22    capital structure, the utility's actual cost of debt for 
23    the applicable calendar year and a cost of equity, which 
24    shall be equal to the baseline cost of equity approved by 
25    the Commission for the utility's electric distribution 
26    rates case effective during the applicable year, whether 
 
 
10400SB0025ham004- 739 -LRB104 16098 AAS 29398 a

1    those rates are set pursuant to Section 9-201, 
2    subparagraph (B) of paragraph (3) of subsection (d) of 
3    Section 16-108.18, or any successor electric distribution 
4    ratemaking paradigm calculated as the sum of (i) the 
5    average for the applicable calendar year of the monthly 
6    average yields of 30-year U.S. Treasury bonds published by 
7    the Board of Governors of the Federal Reserve System in 
8    its weekly H.15 Statistical Release or successor 
9    publication; and (ii) 580 basis points, including a 
10    revenue conversion factor calculated to recover or refund 
11    all additional income taxes that may be payable or 
12    receivable as a result of that return.
13        When an electric utility creates a regulatory asset 
14    under the provisions of this paragraph (1) of subsection 
15    (h), the costs are recovered over a period during which 
16    customers also receive a benefit, which is in the public 
17    interest. Accordingly, it is the intent of the General 
18    Assembly that an electric utility that elects to create a 
19    regulatory asset under the provisions of this paragraph 
20    (1) shall recover all of the associated costs, including, 
21    but not limited to, its cost of capital as set forth in 
22    this paragraph (1). After the Commission has approved the 
23    prudence and reasonableness of the costs that comprise the 
24    regulatory asset, the electric utility shall be permitted 
25    to recover all such costs, and the value and 
26    recoverability through rates of the associated regulatory 
 
 
10400SB0025ham004- 740 -LRB104 16098 AAS 29398 a

1    asset shall not be limited, altered, impaired, or reduced. 
2    To enable the financing of the incremental capital 
3    expenditures, including regulatory assets, for electric 
4    utilities that serve less than 3,000,000 retail customers 
5    but more than 500,000 retail customers in the State, the 
6    utility's actual year-end capital structure that includes 
7    a common equity ratio, excluding goodwill, of up to and 
8    including 50% of the total capital structure shall be 
9    deemed reasonable and used to set rates.
10        (2) The utility, at its election, may recover all of 
11    the costs as part of a filing for a general increase in 
12    rates under Article IX of this Act, as part of an annual 
13    filing to update a performance-based formula rate under 
14    Section 16-108.18 subsection (d) of Section 16-108.5 of 
15    this Act, or through an automatic adjustment clause 
16    tariff, provided that nothing in this paragraph (2) 
17    permits the double recovery of such costs from customers. 
18    If the utility elects to recover the costs it incurs under 
19    subsections (b), (b-5), and (c), and (e) through an 
20    automatic adjustment clause tariff, the utility may file 
21    its proposed tariff together with the tariff it files 
22    under subsection (b) of this Section or at a later time. 
23    The proposed tariff shall provide for an annual 
24    reconciliation, less any deferred taxes related to the 
25    reconciliation, with interest at an annual rate of return 
26    equal to the utility's weighted average cost of capital as 
 
 
10400SB0025ham004- 741 -LRB104 16098 AAS 29398 a

1    calculated under paragraph (1) of this subsection (h), 
2    including a revenue conversion factor calculated to 
3    recover or refund all additional income taxes that may be 
4    payable or receivable as a result of that return, of the 
5    revenue requirement reflected in rates for each calendar 
6    year, beginning with the calendar year in which the 
7    utility files its automatic adjustment clause tariff under 
8    this subsection (h), with what the revenue requirement 
9    would have been had the actual cost information for the 
10    applicable calendar year been available at the filing 
11    date. The Commission shall review the proposed tariff and 
12    may make changes to the tariff that are consistent with 
13    this Section and with the Commission's authority under 
14    Article IX of this Act, subject to notice and hearing. 
15    Following notice and hearing, the Commission shall issue 
16    an order approving, or approving with modification, such 
17    tariff no later than 240 days after the utility files its 
18    tariff.
19    (i) (Blank). An electric utility shall recover from its 
20retail customers, on a volumetric basis, all of the costs of 
21the rebates made under a tariff or tariffs placed into effect 
22under subsection (e) of this Section, including, but not 
23limited to, the value of the rebates and all costs incurred by 
24the utility to comply with and implement subsection (e) of 
25this Section, consistent with the following provisions:
26        (1) The utility may defer a portion of its costs as a 
 
 
10400SB0025ham004- 742 -LRB104 16098 AAS 29398 a

1    regulatory asset. The Commission shall determine the 
2    portion that may be appropriately deferred as a regulatory 
3    asset. Factors that the Commission shall consider in 
4    determining the portion of costs that shall be deferred as 
5    a regulatory asset include, but are not limited to: (i) 
6    whether and the extent to which a cost effectively 
7    deferred or avoided other distribution system operating 
8    costs or capital expenditures; (ii) the extent to which a 
9    cost provides environmental benefits; (iii) the extent to 
10    which a cost improves system reliability or resilience; 
11    (iv) the electric utility's distribution system plan 
12    developed pursuant to Section 16-105.17 of this Act; (v) 
13    the extent to which a cost advances equity principles; and 
14    (vi) such other factors as the Commission deems 
15    appropriate. The remainder of costs shall be deemed an 
16    operating expense and shall be recoverable if found 
17    prudent and reasonable by the Commission.    
18        The total costs deferred as a regulatory asset shall 
19    be amortized over a 15-year period. The unamortized 
20    balance shall be recognized as of December 31 for a given 
21    year. The utility shall also earn a return on the total of 
22    the unamortized balance of the regulatory assets, less any 
23    deferred taxes related to the unamortized balance, at an 
24    annual rate equal to the utility's weighted average cost 
25    of capital that includes, based on a year-end capital 
26    structure, the utility's actual cost of debt for the 
 
 
10400SB0025ham004- 743 -LRB104 16098 AAS 29398 a

1    applicable calendar year and a cost of equity, which shall 
2    be calculated as the sum of: (I) the average for the 
3    applicable calendar year of the monthly average yields of 
4    30-year U.S. Treasury bonds published by the Board of 
5    Governors of the Federal Reserve System in its weekly H.15 
6    Statistical Release or successor publication; and (II) 580 
7    basis points, including a revenue conversion factor 
8    calculated to recover or refund all additional income 
9    taxes that may be payable or receivable as a result of that 
10    return.
11        (2) The utility may recover all of the costs through 
12    an automatic adjustment clause tariff, on a volumetric 
13    basis. The utility may file its proposed cost-recovery 
14    tariff together with the tariff it files under subsection 
15    (e) of this Section or at a later time. The proposed tariff 
16    shall provide for an annual reconciliation, less any 
17    deferred taxes related to the reconciliation, with 
18    interest at an annual rate of return equal to the 
19    utility's weighted average cost of capital as calculated 
20    under paragraph (1) of this subsection (i), including a 
21    revenue conversion factor calculated to recover or refund 
22    all additional income taxes that may be payable or 
23    receivable as a result of that return, of the revenue 
24    requirement reflected in rates for each calendar year, 
25    beginning with the calendar year in which the utility 
26    files its automatic adjustment clause tariff under this 
 
 
10400SB0025ham004- 744 -LRB104 16098 AAS 29398 a

1    subsection (i), with what the revenue requirement would 
2    have been had the actual cost information for the 
3    applicable calendar year been available at the filing 
4    date. The Commission shall review the proposed tariff and 
5    may make changes to the tariff that are consistent with 
6    this Section and with the Commission's authority under 
7    Article IX of this Act, subject to notice and hearing. 
8    Following notice and hearing, the Commission shall issue 
9    an order approving, or approving with modification, such 
10    tariff no later than 240 days after the utility files its 
11    tariff.    
12    (j) No later than 90 days after the Commission enters an 
13order, or order on rehearing, whichever is later, approving an 
14electric utility's proposed tariff under this Section, the 
15electric utility shall provide notice of the availability of 
16rebates under this Section.
17    (k) No later than January 1, 2030, the utilities shall 
18file with the Commission a report that includes:
19        (1) the number and geographic distribution of 
20    participants receiving rebates pursuant to this Section;
21        (2) impacts to energy supply prices and wholesale 
22    market activities;
23        (3) impacts on distribution system investments and 
24    planning; and
25        (4) any other values deemed relevant by the 
26    Commission.
 
 
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1    (l) Upon petition by the applicable electric utility or on 
2its own motion, the Commission may adjust rebate levels for 
3new customers and make other appropriate changes to the rebate 
4program in a manner that is consistent with the State's clean 
5energy goals and the public interest.    
6(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 
7103-1066, eff. 2-20-25.)
 
8    (220 ILCS 5/16-107.8 new)
9    Sec. 16-107.8. Time-of-use pricing.
10    (a) The General Assembly finds that market-based 
11time-of-use rates and pricing plans can reduce costs and help 
12the State achieve its energy policy goals by improving load 
13shape, encouraging energy conservation, and shifting usage 
14away from periods where fossil fuels are used. By providing 
15consumers information relating the costs of service to the 
16time of energy usage, time-of-use rates can help consumers 
17reduce energy bills by using electricity when it is less 
18costly.
19    (b) An electric utility shall offer at least one 
20market-based rate option for eligible retail customers, 
21including, but not limited to, customers participating in net 
22electricity metering under the terms of Section 16-107.5, who 
23choose to take power and energy supply service from the 
24utility. The provisions of Section 16-107.5 notwithstanding, 
25energy credits for net-metering customers shall be valued at 
 
 
10400SB0025ham004- 746 -LRB104 16098 AAS 29398 a

1the same price per kilowatt-hour as the price per 
2kilowatt-hour that the electric service provider would charge 
3for kilowatt-hour energy sales during the same hourly 
4time-of-use period. The utility shall file its time-of-use 
5rate tariff no later than 120 days after the effective date of 
6this amendatory Act of the 104th General Assembly. The tariff 
7or tariffs shall be subject to the following requirements:
8        (1) If more than one tariff is proposed, at least one 
9    tariff shall include at least the following 3 time blocks:
10            (A) a peak time block of consecutive hours best 
11        reflecting the average consecutive highest system 
12        power and energy use per hour in a calendar day;
13            (B) an off-peak time block, which reflects the 
14        next highest system power and energy demands in a 
15        calendar day; and
16            (C) a super-off-peak time block, defined as all 
17        other hours in a calendar day.
18            Time blocks shall reflect the hour and weekday for 
19        which the costs of services outlined in paragraphs (2) 
20        and (3) of this subsection (b) are charged.
21        (2) The tariff or tariffs shall describe the 
22    methodology for determining the prices for each time block 
23    using the applicable average zonal and capacity prices of 
24    the PJM Interconnection, LLC (PJM) and the Midcontinent 
25    Independent System Operator (MISO) and describe the manner 
26    in which customers who elect time-of-use pricing will be 
 
 
10400SB0025ham004- 747 -LRB104 16098 AAS 29398 a

1    provided with the time blocks, associated block pricing, 
2    and day-ahead energy prices. Costs for electric capacity 
3    shall be determined in a manner that recovers the capacity 
4    obligation costs incurred by the electric utility.
5        (3) The time-of-use rate shall include the costs of 
6    transmission services and the charges for network 
7    integration transmission service, transmission 
8    enhancement, and locational reliability, as these terms 
9    are defined in the PJM and MISO Open Access Transmission 
10    Tariffs and manuals. If the Open Access Transmission 
11    Tariff or the manuals subsequently rename those terms, the 
12    services reflected under those terms shall continue to be 
13    included in the time-of-use rate described in this 
14    paragraph (3).
15        (4) Adjustments to the charges set by the tariff may 
16    be made on a monthly basis and adjustments to the time 
17    blocks may be made on an annual basis. A utility shall 
18    submit to the Commission, through a supplemental 
19    information sheet, a tariff schedule. Customers shall be 
20    provided at least 2 weeks advance notice of any changes to 
21    charges or time blocks.
22        (5) A purchased energy adjustment shall be calculated 
23    to fully recover costs to supply power and energy. A 
24    utility shall procure power and energy in the applicable 
25    day-ahead market.
26    (c) The Commission shall approve or approve with 
 
 
10400SB0025ham004- 748 -LRB104 16098 AAS 29398 a

1modifications the tariff or tariffs after notice and hearing. 
2A proceeding under this subsection (c) may not exceed 240 days 
3in length.
4    (d) An electric utility shall submit an annual report to 
5the Commission no later than April 1 of each year that 
6describes the operation and results of the rate option, 
7including information concerning the number and types of 
8customers using the rate option, changes in customers' energy 
9use patterns, an assessment of the value of the rate option to 
10both participants and nonparticipants, and recommendations 
11concerning modification of the rate option and the tariff or 
12tariffs filed under this Section. The report shall be made 
13available to the public on the Commission's website.
14    (e) Once a tariff or tariffs has been in effect, the 
15Commission may, upon complaint, petition, or its own 
16initiative, open a proceeding to investigate whether changes 
17or modifications, consistent with the requirements of this 
18Section, to the tariff or tariffs, rate option administration, 
19or any other rate option element is necessary to achieve the 
20goals described in subsection (a). Such a proceeding may not 
21last more than 180 days from the date upon which the 
22investigation was opened.
23    (f) An electric utility shall be entitled to recover 
24prudent and reasonable costs incurred in complying with this 
25Section from its eligible retail customers.
26    (g) An electric utility's tariff or tariffs filed under 
 
 
10400SB0025ham004- 749 -LRB104 16098 AAS 29398 a

1this Section shall be subject to the provisions of Article IX 
2as long as such provisions do not conflict with this Section.
3    (h) This Section does not apply to an electric utility 
4that provides service to 100,000 or fewer customers.    
 
5    (220 ILCS 5/16-107.9 new)
6    Sec. 16-107.9. Virtual power plant program.
7    (a) As used in this Section:
8    "Aggregator" means a third-party entity that participates 
9in the program, other than the electric utility or its 
10affiliate, that (i) represents and aggregates the load of 
11participating customers who collectively have the ability to 
12deploy 100 kilowatts or more of deployment of eligible devices 
13and (ii) is responsible for performance of the aggregation in 
14the program.
15    "Battery" means a behind-the-meter energy storage device 
16and associated equipment that operate together to fulfill 
17program requirements.
18    "Commission" means the Illinois Commerce Commission.
19    "Customer" means an active electric service account holder 
20of a utility.
21    "Direct participant" means a customer that enrolls in the 
22program directly with the utility, rather than participating 
23in the program through an aggregator.
24    "Distributed energy resource" has the meaning set forth in 
25Section 16-107.6.
 
 
10400SB0025ham004- 750 -LRB104 16098 AAS 29398 a

1    "Distributed energy resources management system" means a 
2platform that may be used by distribution system operators or 
3utilities to integrate grid resources, such as distributed 
4energy resources, into system operations.
5    "Eligible device" means a customer or third party-owned 
6distributed energy resource that satisfies the requirements 
7for participation in the program as specified in the relevant 
8program rider. "Eligible device" also means any device that 
9can be controlled to respond to pricing, provide services, 
10including decrease peak electricity demand or shift demand 
11from peak to off-peak periods, or inject power to the grid. 
12"Eligible device" includes, but is not limited to, 
13behind-the-meter energy storage systems, smart thermostats, 
14electric vehicle batteries, including fleets, and distributed 
15renewable energy devices paired with one or more energy 
16storage systems.
17    "Emergency event" means an event called by the utility 
18with fewer than 24 hours notice.
19    "Energy storage system" has the meaning set forth in 
20subsection (a) of Section 16-107.6.
21    "Enrolled customer" means a customer that participates in 
22the program through either an aggregator or as a direct 
23participant.
24    "Enrolled device" means an enrolled customer's eligible 
25device, as specified in the relevant tariff.
26    "Enterprise distributed energy resources management 
 
 
10400SB0025ham004- 751 -LRB104 16098 AAS 29398 a

1system" means a platform operated by the electric utility that 
2interfaces with a grid-edge distributed energy resources 
3management system to integrate distributed energy resources 
4into utility electric system operations.
5    "Grid-edge distributed energy resources management system" 
6means a platform owned by a party other than the electric 
7utility that may be used to integrate distributed energy 
8resources.
9    "Grid event" means a grid condition for which the utility 
10schedules or remotely dispatches enrolled devices to respond 
11to, as specified in the grid service opportunities for each 
12tariff.
13    "Grid service" means a capacity, energy, or ancillary 
14service that supports grid operations.
15    "Participating customer" means an aggregator or a direct 
16retail customer, as defined in Section 16-102, with one or 
17more eligible devices.
18    "Performance payment" means a payment made to the 
19participant based on the performance of an enrolled device 
20providing a grid service during a grid event.
21    "Performance payment rate" means the compensation rate 
22paid to participants for providing a particular grid service 
23during a grid event.
24    "Smart inverter" has the meaning set forth in subsection 
25(a) of Section 16-107.6.
26    "Upfront payment" means a one-time payment made at the 
 
 
10400SB0025ham004- 752 -LRB104 16098 AAS 29398 a

1time of enrollment.
2    "Virtual power plant" means an aggregation of 
3behind-the-meter distributed energy resources operated in 
4coordination to provide one or more grid services.
5    (b) The General Assembly finds that:
6        (1) virtual power plants are dynamic load management 
7    and energy supply resources that can support grid 
8    operations, reduce ratepayer costs, and achieve other 
9    important public policy goals;
10        (2) virtual power plants can reduce demand for grid 
11    supplied electricity during peak periods, shift 
12    electricity consumption out of peak periods, make 
13    renewable energy generated during off-peak periods 
14    available for use during peak periods, supply energy to 
15    the grid at desired times, provide frequency regulation, 
16    voltage support, and other ancillary services, reduce 
17    strain on the distribution system, manage localized peaks, 
18    improve system resiliency and reliability, and provide 
19    other grid services;
20        (3) virtual power plants can facilitate and optimize 
21    the utilization of electrical generation from wind and 
22    solar energy to help utilities increase hosting capacity 
23    and integrate more renewable energy resources;
24        (4) virtual power plants can reduce costs to 
25    ratepayers by utilizing customer-sited resources to 
26    provide grid services, avoiding or reducing reliance on 
 
 
10400SB0025ham004- 753 -LRB104 16098 AAS 29398 a

1    fossil-fuel fired peaker plants, avoiding or deferring the 
2    need to construct new and more costly grid scale 
3    resources, optimizing the use of existing assets, and 
4    avoiding or deferring distribution and transmission system 
5    upgrades and other grid investments;
6        (5) virtual power plants can promote equity by 
7    reducing costs for all ratepayers, expanding access to 
8    distributed energy resources among low-income and 
9    moderate-income customers through improved distributed 
10    energy resource finance ability, and providing other 
11    important co-benefits, including reduction in emissions of 
12    greenhouse gases and other pollutants, especially in 
13    environmental justice and other disadvantaged communities 
14    that host fossil fuel generation plants;
15        (6) the United States Department of Energy estimates 
16    that the United States could deploy 80 to 160 gigawatts of 
17    virtual power plants by 2030, a tripling of current 
18    levels, to support the rapid electrification of vehicles 
19    and homes and provide on the order of $10,000,000,000 in 
20    ratepayer savings annually. The deployment of virtual 
21    power plants can provide energy cost savings and other 
22    benefits to the people of Illinois;
23        (7) there are significant barriers to deployment and 
24    operation of virtual power plants, including the need for 
25    statutory and regulatory guidance and support, greater 
26    consistency in virtual power plant programs across 
 
 
10400SB0025ham004- 754 -LRB104 16098 AAS 29398 a

1    regulatory jurisdictions, and for utility commitments to 
2    incorporate the use of virtual power plants into system 
3    operations and long-term resource planning;
4        (8) it is in the public interest to advance customer 
5    choice and leverage the expertise of private, non-utility 
6    entities to advance innovation and implement 
7    cost-effective clean energy solutions; and
8        (9) the policy of Illinois shall be to maximize the 
9    use of virtual power plants comprised of customer-owned 
10    and third party-owned distributed energy resources to 
11    deliver system services and other benefits through utility 
12    administered virtual power plant programs in accordance 
13    with the provisions of this amendatory Act of the 104th 
14    General Assembly.
15    (c) No later than December 31, 2028, the Commission shall 
16approve at least one virtual power plant tariff for each 
17electric utility serving more than 300,000 customers in the 
18State as of January 1, 2023. Each utility shall file a tariff 
19or tariffs for approval no later than December 31, 2027 to 
20allow retail customers in the electric utility's service areas 
21to participate in a virtual power plant program proposal 
22consistent with the provisions of this Section. The Commission 
23shall provide opportunities for stakeholders to provide input 
24on the virtual power plant programs proposed for 
25implementation by each utility, which the Commission shall 
26take into consideration in its review of each utility's 
 
 
10400SB0025ham004- 755 -LRB104 16098 AAS 29398 a

1filing. No later than one year after the utility's filing, the 
2Commission shall approve or modify and approve each utility's 
3virtual power plant program proposal for immediate 
4implementation by the utility.
5    (d) The virtual power plant program filed under subsection 
6(c) shall be developed for implementation through a tariff 
7offering with standard terms and conditions for participation. 
8The virtual power plant program tariff shall allow for 
9customers with battery storage, non-battery storage and 
10electric vehicle technologies to enroll the devices in the 
11program through aggregators or directly with the utility. The 
12virtual power plant program tariff shall:
13        (1) provide a mechanism to incorporate existing 
14    programs, such as smart thermostat demand-response or 
15    electric vehicle charging programs currently offered by 
16    the utility, under the virtual power plant program 
17    framework;
18        (2) provide grid services opportunities for each 
19    eligible technology that customers and aggregators may 
20    provide, which shall include, at minimum, reducing the 
21    utility's applicable capacity and transmission obligations 
22    and capturing daily wholesale energy arbitrage 
23    opportunities through provision of grid services;
24        (3) provide additional functions and grid service 
25    opportunities that the Commission determines are 
26    supportive of efficient planning and operation of the 
 
 
10400SB0025ham004- 756 -LRB104 16098 AAS 29398 a

1    electrical grid, including:
2            (A) minimizing the use of fossil fuels at peak 
3        times;
4            (B) local peak demand reductions;
5            (C) locational value;
6            (D) the avoidance or deferral of local 
7        transmission or distribution upgrades or capacity 
8        expansion;
9            (E) voltage support and other ancillary services; 
10        and
11            (F) emergency grid services;
12        (4) provide operational parameters, which shall 
13    include, at a minimum:
14            (A) minimum and maximum numbers of grid events for 
15        which the utility may require dispatch from the 
16        enrolled distributed energy resources;
17            (B) months of the year that grid events may occur;
18            (C) days of the week that grid events may occur;
19            (D) times of day that grid events may occur;
20            (E) maximum duration of grid events; and
21            (F) minimum day-ahead advance notification 
22        requirement of grid events, except for emergency 
23        events, as applicable;
24        (5) include provisions for aggregators to participate 
25    in the virtual power plant program, participate in the 
26    utility's distributed energy resource management system as 
 
 
10400SB0025ham004- 757 -LRB104 16098 AAS 29398 a

1    available, automatically enroll and manage their 
2    customers' participation, receive dispatch signals and 
3    other communications from the utility, deliver performance 
4    measurement and verification data to the utility, and 
5    receive virtual power plant program payments directly from 
6    the utility;
7        (6) include provisions that provide a standardized 
8    process for any eligible aggregator to enroll in the 
9    program and authorize the eligible aggregators to manage 
10    individual customer device participation without 
11    additional authorizations from the utility;
12        (7) include provisions that allow a participating 
13    customer with multiple eligible devices to enroll the 
14    technologies either directly without an aggregator or 
15    through one or more aggregators in applicable programs 
16    under the tariff approved under this Section, provided 
17    that no particular device is accounted for more than once;
18        (8) include provisions for direct participant 
19    customers to participate with the utility's distributed 
20    energy resource management system as available, receive 
21    dispatch signals and other communications from the 
22    utility, deliver performance measurement and verification 
23    data to the utility, and receive virtual power plant 
24    program payments directly from the utility. Any provisions 
25    implementing this subpart that necessitate the 
26    installation of equipment to enable direct participation 
 
 
10400SB0025ham004- 758 -LRB104 16098 AAS 29398 a

1    via the utility shall apply to customers who elect to 
2    participate as a direct participant and shall not be 
3    required of customers who participate via an aggregator or 
4    to customers who do not participate in the virtual power 
5    plant program;
6        (9) provide for measurement and verification of 
7    battery non-battery, and electric vehicle technologies 
8    performance directly at the device without the requirement 
9    for the installation of an additional meter;
10        (10) include upfront payment or performance payment 
11    compensation mechanisms for the peak reduction service, as 
12    well as for non-battery and electric vehicle technologies 
13    as the Commission deems appropriate. The performance 
14    payment shall be based on the average capacity provided 
15    during grid events. The Commission shall approve 
16    additional compensation mechanisms as it determines 
17    appropriate for other grid services provided under the 
18    battery, non-battery and electric vehicle riders. The 
19    virtual power plant program shall not assess penalties for 
20    non-performance; provided, however, that the Commission 
21    may approve reasonable mechanisms to disenroll customers 
22    for continued non-performance;
23        (11) enable low-to-moderate income customers, 
24    community-driven community solar projects, and customers 
25    whose electric service has not been declared competitive 
26    pursuant to Section 16-113 as of July 1, 2011 located in 
 
 
10400SB0025ham004- 759 -LRB104 16098 AAS 29398 a

1    equity investment eligible investment communities to 
2    receive a higher upfront enrollment payment. The 
3    Commission shall coordinate with State energy officials 
4    and departments to make funding from federal programs and 
5    such other sources as may be available for use in 
6    providing higher upfront payments to customers classes as 
7    may be approved by the Commission in accordance with this 
8    subsection;
9        (12) provide that the performance payment rate 
10    applicable at the time of enrollment shall be for 5 years, 
11    after which time the participant may reenroll at the then 
12    applicable performance payment rate for an additional 
13    5-year term;
14        (13) provide for a transition of customers from the 
15    scheduled dispatch program described in Section 16-107.6 
16    to the virtual power plant program; and
17        (14) allow enrolled customers to participate in other 
18    applicable interconnection tariffs and grid service 
19    programs outside the virtual power plant program, so long 
20    as it does not result in double-counting of benefits for 
21    the same grid services.
22    (e) The Commission may adopt other reasonable requirements 
23for participation consistent with this subsection, provided 
24that collateral from an aggregator shall not be required for 
25participation.
26    (f) The utility may contract with a third party-owned 
 
 
10400SB0025ham004- 760 -LRB104 16098 AAS 29398 a

1distributed energy resource management system provider to 
2assist with program implementation; however, implementation 
3shall not be delayed due to the lack of utility-owned 
4distributed energy resource management system capabilities or 
5third party-owned distributed energy resource management 
6system capabilities.
7    (g) The utility shall not send or receive dispatch signals 
8directly to or from any participating customer represented by 
9an aggregator for an event under the virtual power plant 
10program described in this Section.
11    (h) Participating aggregators shall have capabilities to 
12receive event signals from utilities or utility-contracted 
13distributed energy resources management system providers.
14    (i) Utilities shall recover reasonably and prudently 
15incurred costs to facilitate the virtual power plant program 
16approved under subsection (c), including, but not limited to, 
17distributed energy resource management systems provider and 
18other service contract costs, operations and maintenance 
19expenses, information technology costs, and other costs, 
20expenses, and investments that the Commission finds necessary 
21and prudent for the development and implementation of the 
22program. The utility shall recover the cost of virtual power 
23plant program upfront payments and performance payments and 
24such other payments made to participants through the tariff 
25filed pursuant to subsection (h) of Section 16-107.6.
26    (j) No later than January 31 of each year, each utility 
 
 
10400SB0025ham004- 761 -LRB104 16098 AAS 29398 a

1shall file an annual report that includes, but is not limited 
2to:
3        (1) the total capacity enrolled in each program rider 
4    developed in accordance with the requirements of Section, 
5    broken down by technology type, customer class, and 
6    aggregator and direct participant status for each grid 
7    service opportunity offered in the prior calendar year;
8        (2) recommendations to increase participation in the 
9    virtual power plant program; and
10        (3) any other information that the Commission may 
11    require.
12    (k) Each utility shall amend existing tariffs and 
13procedures that limit the ability of customers to participate 
14in providing grid services under the program, such as 
15limitations on charging energy storage devices with grid 
16energy or exporting energy to the grid from battery discharge.
17    (l) The tariffs approved by the Commission shall not 
18reflect any additional charges, fees, or insurance 
19requirements imposed on those owning or operating 
20demand-response technologies beyond those imposed on similarly 
21situated customers that do not own or operate demand-response 
22technologies.    
23    (m) As a condition of participating in the programs 
24described in this Section, prior to enrollment of a customer 
25by an aggregator, the aggregator shall disclose the following:
26        (1) the payments, expressed as an amount or a formula, 
 
 
10400SB0025ham004- 762 -LRB104 16098 AAS 29398 a

1    to be provided to the customer;
2        (2) between the aggregator and customer, who is 
3    responsible for paying penalties or fees; and
4        (3) between the aggregator and customer, who is 
5    responsible for posting collateral, if required.
6    Any tariff authorized by this Section shall incorporate 
7the requirements under this subsection and shall require the 
8electric utility to establish a complaint and Commission 
9notification process and, on order of the Commission, suspend 
10any aggregator repeatedly or egregiously violating such 
11requirements.    
 
12    (220 ILCS 5/16-108)
13    Sec. 16-108. Recovery of costs associated with the 
14provision of delivery and other services.
15    (a) An electric utility shall file a delivery services 
16tariff with the Commission at least 210 days prior to the date 
17that it is required to begin offering such services pursuant 
18to this Act. An electric utility shall provide the components 
19of delivery services that are subject to the jurisdiction of 
20the Federal Energy Regulatory Commission at the same prices, 
21terms and conditions set forth in its applicable tariff as 
22approved or allowed into effect by that Commission. The 
23Commission shall otherwise have the authority pursuant to 
24Article IX to review, approve, and modify the prices, terms 
25and conditions of those components of delivery services not 
 
 
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1subject to the jurisdiction of the Federal Energy Regulatory 
2Commission, including the authority to determine the extent to 
3which such delivery services should be offered on an unbundled 
4basis. In making any such determination the Commission shall 
5consider, at a minimum, the effect of additional unbundling on 
6(i) the objective of just and reasonable rates, (ii) electric 
7utility employees, and (iii) the development of competitive 
8markets for electric energy services in Illinois.
9    (b) The Commission shall enter an order approving, or 
10approving as modified, the delivery services tariff no later 
11than 30 days prior to the date on which the electric utility 
12must commence offering such services. The Commission may 
13subsequently modify such tariff pursuant to this Act.
14    (c) The electric utility's tariffs shall define the 
15classes of its customers for purposes of delivery services 
16charges. Delivery services shall be priced and made available 
17to all retail customers electing delivery services in each 
18such class on a nondiscriminatory basis regardless of whether 
19the retail customer chooses the electric utility, an affiliate 
20of the electric utility, or another entity as its supplier of 
21electric power and energy. Charges for delivery services shall 
22be cost based, and shall allow the electric utility to recover 
23the costs of providing delivery services through its charges 
24to its delivery service customers that use the facilities and 
25services associated with such costs. Such costs shall include 
26the costs of owning, operating and maintaining transmission 
 
 
10400SB0025ham004- 764 -LRB104 16098 AAS 29398 a

1and distribution facilities. The Commission shall also be 
2authorized to consider whether, and if so to what extent, the 
3following costs are appropriately included in the electric 
4utility's delivery services rates: (i) the costs of that 
5portion of generation facilities used for the production and 
6absorption of reactive power in order that retail customers 
7located in the electric utility's service area can receive 
8electric power and energy from suppliers other than the 
9electric utility, and (ii) the costs associated with the use 
10and redispatch of generation facilities to mitigate 
11constraints on the transmission or distribution system in 
12order that retail customers located in the electric utility's 
13service area can receive electric power and energy from 
14suppliers other than the electric utility. Nothing in this 
15subsection shall be construed as directing the Commission to 
16allocate any of the costs described in (i) or (ii) that are 
17found to be appropriately included in the electric utility's 
18delivery services rates to any particular customer group or 
19geographic area in setting delivery services rates.
20    (d) The Commission shall establish charges, terms and 
21conditions for delivery services that are just and reasonable 
22and shall take into account customer impacts when establishing 
23such charges. In establishing charges, terms and conditions 
24for delivery services, the Commission shall take into account 
25voltage level differences. A retail customer shall have the 
26option to request to purchase electric service at any delivery 
 
 
10400SB0025ham004- 765 -LRB104 16098 AAS 29398 a

1service voltage reasonably and technically feasible from the 
2electric facilities serving that customer's premises provided 
3that there are no significant adverse impacts upon system 
4reliability or system efficiency. A retail customer shall also 
5have the option to request to purchase electric service at any 
6point of delivery that is reasonably and technically feasible 
7provided that there are no significant adverse impacts on 
8system reliability or efficiency. Such requests shall not be 
9unreasonably denied.
10    (e) Electric utilities shall recover the costs of 
11installing, operating or maintaining facilities for the 
12particular benefit of one or more delivery services customers, 
13including without limitation any costs incurred in complying 
14with a customer's request to be served at a different voltage 
15level, directly from the retail customer or customers for 
16whose benefit the costs were incurred, to the extent such 
17costs are not recovered through the charges referred to in 
18subsections (c) and (d) of this Section.
19    (f) An electric utility shall be entitled but not required 
20to implement transition charges in conjunction with the 
21offering of delivery services pursuant to Section 16-104. If 
22an electric utility implements transition charges, it shall 
23implement such charges for all delivery services customers and 
24for all customers described in subsection (h), but shall not 
25implement transition charges for power and energy that a 
26retail customer takes from cogeneration or self-generation 
 
 
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1facilities located on that retail customer's premises, if such 
2facilities meet the following criteria:    
3        (i) the cogeneration or self-generation facilities 
4    serve a single retail customer and are located on that 
5    retail customer's premises (for purposes of this 
6    subparagraph and subparagraph (ii), an industrial or 
7    manufacturing retail customer and a third party contractor 
8    that is served by such industrial or manufacturing 
9    customer through such retail customer's own electrical 
10    distribution facilities under the circumstances described 
11    in subsection (vi) of the definition of "alternative 
12    retail electric supplier" set forth in Section 16-102, 
13    shall be considered a single retail customer);    
14        (ii) the cogeneration or self-generation facilities 
15    either (A) are sized pursuant to generally accepted 
16    engineering standards for the retail customer's electrical 
17    load at that premises (taking into account standby or 
18    other reliability considerations related to that retail 
19    customer's operations at that site) or (B) if the facility 
20    is a cogeneration facility located on the retail 
21    customer's premises, the retail customer is the thermal 
22    host for that facility and the facility has been designed 
23    to meet that retail customer's thermal energy requirements 
24    resulting in electrical output beyond that retail 
25    customer's electrical demand at that premises, comply with 
26    the operating and efficiency standards applicable to 
 
 
10400SB0025ham004- 767 -LRB104 16098 AAS 29398 a

1    "qualifying facilities" specified in title 18 Code of 
2    Federal Regulations Section 292.205 as in effect on the 
3    effective date of this amendatory Act of 1999;    
4        (iii) the retail customer on whose premises the 
5    facilities are located either has an exclusive right to 
6    receive, and corresponding obligation to pay for, all of 
7    the electrical capacity of the facility, or in the case of 
8    a cogeneration facility that has been designed to meet the 
9    retail customer's thermal energy requirements at that 
10    premises, an identified amount of the electrical capacity 
11    of the facility, over a minimum 5-year period; and    
12        (iv) if the cogeneration facility is sized for the 
13    retail customer's thermal load at that premises but 
14    exceeds the electrical load, any sales of excess power or 
15    energy are made only at wholesale, are subject to the 
16    jurisdiction of the Federal Energy Regulatory Commission, 
17    and are not for the purpose of circumventing the 
18    provisions of this subsection (f).
19If a generation facility located at a retail customer's 
20premises does not meet the above criteria, an electric utility 
21implementing transition charges shall implement a transition 
22charge until December 31, 2006 for any power and energy taken 
23by such retail customer from such facility as if such power and 
24energy had been delivered by the electric utility. Provided, 
25however, that an industrial retail customer that is taking 
26power from a generation facility that does not meet the above 
 
 
10400SB0025ham004- 768 -LRB104 16098 AAS 29398 a

1criteria but that is located on such customer's premises will 
2not be subject to a transition charge for the power and energy 
3taken by such retail customer from such generation facility if 
4the facility does not serve any other retail customer and 
5either was installed on behalf of the customer and for its own 
6use prior to January 1, 1997, or is both predominantly fueled 
7by byproducts of such customer's manufacturing process at such 
8premises and sells or offers an average of 300 megawatts or 
9more of electricity produced from such generation facility 
10into the wholesale market. Such charges shall be calculated as 
11provided in Section 16-102, and shall be collected on each 
12kilowatt-hour delivered under a delivery services tariff to a 
13retail customer from the date the customer first takes 
14delivery services until December 31, 2006 except as provided 
15in subsection (h) of this Section. Provided, however, that an 
16electric utility, other than an electric utility providing 
17service to at least 1,000,000 customers in this State on 
18January 1, 1999, shall be entitled to petition for entry of an 
19order by the Commission authorizing the electric utility to 
20implement transition charges for an additional period ending 
21no later than December 31, 2008. The electric utility shall 
22file its petition with supporting evidence no earlier than 16 
23months, and no later than 12 months, prior to December 31, 
242006. The Commission shall hold a hearing on the electric 
25utility's petition and shall enter its order no later than 8 
26months after the petition is filed. The Commission shall 
 
 
10400SB0025ham004- 769 -LRB104 16098 AAS 29398 a

1determine whether and to what extent the electric utility 
2shall be authorized to implement transition charges for an 
3additional period. The Commission may authorize the electric 
4utility to implement transition charges for some or all of the 
5additional period, and shall determine the mitigation factors 
6to be used in implementing such transition charges; provided, 
7that the Commission shall not authorize mitigation factors 
8less than 110% of those in effect during the 12 months ended 
9December 31, 2006. In making its determination, the Commission 
10shall consider the following factors: the necessity to 
11implement transition charges for an additional period in order 
12to maintain the financial integrity of the electric utility; 
13the prudence of the electric utility's actions in reducing its 
14costs since the effective date of this amendatory Act of 1997; 
15the ability of the electric utility to provide safe, adequate 
16and reliable service to retail customers in its service area; 
17and the impact on competition of allowing the electric utility 
18to implement transition charges for the additional period.
19    (g) The electric utility shall file tariffs that establish 
20the transition charges to be paid by each class of customers to 
21the electric utility in conjunction with the provision of 
22delivery services. The electric utility's tariffs shall define 
23the classes of its customers for purposes of calculating 
24transition charges. The electric utility's tariffs shall 
25provide for the calculation of transition charges on a 
26customer-specific basis for any retail customer whose average 
 
 
10400SB0025ham004- 770 -LRB104 16098 AAS 29398 a

1monthly maximum electrical demand on the electric utility's 
2system during the 6 months with the customer's highest monthly 
3maximum electrical demands equals or exceeds 3.0 megawatts for 
4electric utilities having more than 1,000,000 customers, and 
5for other electric utilities for any customer that has an 
6average monthly maximum electrical demand on the electric 
7utility's system of one megawatt or more, and (A) for which 
8there exists data on the customer's usage during the 3 years 
9preceding the date that the customer became eligible to take 
10delivery services, or (B) for which there does not exist data 
11on the customer's usage during the 3 years preceding the date 
12that the customer became eligible to take delivery services, 
13if in the electric utility's reasonable judgment there exists 
14comparable usage information or a sufficient basis to develop 
15such information, and further provided that the electric 
16utility can require customers for which an individual 
17calculation is made to sign contracts that set forth the 
18transition charges to be paid by the customer to the electric 
19utility pursuant to the tariff.
20    (h) An electric utility shall also be entitled to file 
21tariffs that allow it to collect transition charges from 
22retail customers in the electric utility's service area that 
23do not take delivery services but that take electric power or 
24energy from an alternative retail electric supplier or from an 
25electric utility other than the electric utility in whose 
26service area the customer is located. Such charges shall be 
 
 
10400SB0025ham004- 771 -LRB104 16098 AAS 29398 a

1calculated, in accordance with the definition of transition 
2charges in Section 16-102, for the period of time that the 
3customer would be obligated to pay transition charges if it 
4were taking delivery services, except that no deduction for 
5delivery services revenues shall be made in such calculation, 
6and usage data from the customer's class shall be used where 
7historical usage data is not available for the individual 
8customer. The customer shall be obligated to pay such charges 
9on a lump sum basis on or before the date on which the customer 
10commences to take service from the alternative retail electric 
11supplier or other electric utility, provided, that the 
12electric utility in whose service area the customer is located 
13shall offer the customer the option of signing a contract 
14pursuant to which the customer pays such charges ratably over 
15the period in which the charges would otherwise have applied.
16    (i) An electric utility shall be entitled to add to the 
17bills of delivery services customers charges pursuant to 
18Sections 9-221, 9-222 (except as provided in Section 9-222.1), 
19and Section 16-114 of this Act, Section 5-5 of the Electricity 
20Infrastructure Maintenance Fee Law, Section 6-5 of the 
21Renewable Energy, Energy Efficiency, and Coal Resources 
22Development Law of 1997, and Section 13 of the Energy 
23Assistance Act.
24    (i-5) An electric utility required to impose the Coal to 
25Solar and Energy Storage Initiative Charge provided for in 
26subsection (c-5) of Section 1-75 of the Illinois Power Agency 
 
 
10400SB0025ham004- 772 -LRB104 16098 AAS 29398 a

1Act shall add such charge to the bills of its delivery services 
2customers pursuant to the terms of a tariff conforming to the 
3requirements of subsection (c-5) of Section 1-75 of the 
4Illinois Power Agency Act and this subsection (i-5) and filed 
5with and approved by the Commission. The electric utility 
6shall file its proposed tariff with the Commission on or 
7before July 1, 2022 to be effective, after review and approval 
8or modification by the Commission, beginning January 1, 2023. 
9On or before December 1, 2022, the Commission shall review the 
10electric utility's proposed tariff, including by conducting a 
11docketed proceeding if deemed necessary by the Commission, and 
12shall approve the proposed tariff or direct the electric 
13utility to make modifications the Commission finds necessary 
14for the tariff to conform to the requirements of subsection 
15(c-5) of Section 1-75 of the Illinois Power Agency Act and this 
16subsection (i-5). The electric utility's tariff shall provide 
17for imposition of the Coal to Solar and Energy Storage 
18Initiative Charge on a per-kilowatthour basis to all 
19kilowatthours delivered by the electric utility to its 
20delivery services customers. The tariff shall provide for the 
21calculation of the Coal to Solar and Energy Storage Initiative 
22Charge to be in effect for the year beginning January 1, 2023 
23and each year beginning January 1 thereafter, sufficient to 
24collect the electric utility's estimated payment obligations 
25for the delivery year beginning the following June 1 under 
26contracts for purchase of renewable energy credits entered 
 
 
10400SB0025ham004- 773 -LRB104 16098 AAS 29398 a

1into pursuant to subsection (c-5) of Section 1-75 of the 
2Illinois Power Agency Act and the obligations of the 
3Department of Commerce and Economic Opportunity, or any 
4successor department or agency, which for purposes of this 
5subsection (i-5) shall be referred to as the Department, to 
6make grant payments during such delivery year from the Coal to 
7Solar and Energy Storage Initiative Fund pursuant to grant 
8contracts entered into pursuant to subsection (c-5) of Section 
91-75 of the Illinois Power Agency Act, and using the electric 
10utility's kilowatthour deliveries to its delivery services 
11customers during the delivery year ended May 31 of the 
12preceding calendar year. On or before November 1 of each year 
13beginning November 1, 2022, the Department shall notify the 
14electric utilities of the amount of the Department's estimated 
15obligations for grant payments during the delivery year 
16beginning the following June 1 pursuant to grant contracts 
17entered into pursuant to subsection (c-5) of Section 1-75 of 
18the Illinois Power Agency Act; and each electric utility shall 
19incorporate in the calculation of its Coal to Solar and Energy 
20Storage Initiative Charge the fractional portion of the 
21Department's estimated obligations equal to the electric 
22utility's kilowatthour deliveries to its delivery services 
23customers in the delivery year ended the preceding May 31 
24divided by the aggregate deliveries of both electric utilities 
25to delivery services customers in such delivery year. The 
26electric utility shall remit on a monthly basis to the State 
 
 
10400SB0025ham004- 774 -LRB104 16098 AAS 29398 a

1Treasurer, for deposit in the Coal to Solar and Energy Storage 
2Initiative Fund provided for in subsection (c-5) of Section 
31-75 of the Illinois Power Agency Act, the electric utility's 
4collections of the Coal to Solar and Energy Storage Initiative 
5Charge estimated to be needed by the Department for grant 
6payments pursuant to grant contracts entered into pursuant to 
7subsection (c-5) of Section 1-75 of the Illinois Power Agency 
8Act. The initial charge under the electric utility's tariff 
9shall be effective for kilowatthours delivered beginning 
10January 1, 2023, and thereafter shall be revised to be 
11effective January 1, 2024 and each January 1 thereafter, based 
12on the payment obligations for the delivery year beginning the 
13following June 1. The tariff shall provide for the electric 
14utility to make an annual filing with the Commission on or 
15before November 15 of each year, beginning in 2023, setting 
16forth the Coal to Solar and Energy Storage Initiative Charge 
17to be in effect for the year beginning the following January 1. 
18The electric utility's tariff shall also provide that the 
19electric utility shall make a filing with the Commission on or 
20before August 1 of each year beginning in 2024 setting forth a 
21reconciliation, for the delivery year ended the preceding May 
2231, of the electric utility's collections of the Coal to Solar 
23and Energy Storage Initiative Charge against actual payments 
24for renewable energy credits pursuant to contracts entered 
25into, and the actual grant payments by the Department pursuant 
26to grant contracts entered into, pursuant to subsection (c-5) 
 
 
10400SB0025ham004- 775 -LRB104 16098 AAS 29398 a

1of Section 1-75 of the Illinois Power Agency Act. The tariff 
2shall provide that any excess or shortfall of collections to 
3payments shall be deducted from or added to, on a 
4per-kilowatthour basis, the Coal to Solar and Energy Storage 
5Initiative Charge, over the 6-month period beginning October 1 
6of that calendar year. 
7    (j) If a retail customer that obtains electric power and 
8energy from cogeneration or self-generation facilities 
9installed for its own use on or before January 1, 1997, 
10subsequently takes service from an alternative retail electric 
11supplier or an electric utility other than the electric 
12utility in whose service area the customer is located for any 
13portion of the customer's electric power and energy 
14requirements formerly obtained from those facilities 
15(including that amount purchased from the utility in lieu of 
16such generation and not as standby power purchases, under a 
17cogeneration displacement tariff in effect as of the effective 
18date of this amendatory Act of 1997), the transition charges 
19otherwise applicable pursuant to subsections (f), (g), or (h) 
20of this Section shall not be applicable in any year to that 
21portion of the customer's electric power and energy 
22requirements formerly obtained from those facilities, 
23provided, that for purposes of this subsection (j), such 
24portion shall not exceed the average number of kilowatt-hours 
25per year obtained from the cogeneration or self-generation 
26facilities during the 3 years prior to the date on which the 
 
 
10400SB0025ham004- 776 -LRB104 16098 AAS 29398 a

1customer became eligible for delivery services, except as 
2provided in subsection (f) of Section 16-110.
3    (k) The electric utility shall be entitled to recover 
4through tariffed charges all of the costs associated with the 
5purchase of zero emission credits from zero emission 
6facilities to meet the requirements of subsection (d-5) of 
7Section 1-75 of the Illinois Power Agency Act and all of the 
8costs associated with the purchase of carbon mitigation 
9credits from carbon-free energy resources to meet the 
10requirements of subsection (d-10) of Section 1-75 of the 
11Illinois Power Agency Act. Such costs shall include the costs 
12of procuring the zero emission credits and carbon mitigation 
13credits from carbon-free energy resources, as well as the 
14reasonable costs that the utility incurs as part of the 
15procurement processes and to implement and comply with plans 
16and processes approved by the Commission under subsections 
17(d-5) and (d-10). The costs shall be allocated across all 
18retail customers through a single, uniform cents per 
19kilowatt-hour charge applicable to all retail customers, which 
20shall appear as a separate line item on each customer's bill. 
21The electric utility shall be entitled to recover through 
22tariffed charges approved by the Commission all of the prudent 
23and reasonable costs associated with energy storage resources 
24procurements to meet the energy storage system portfolio 
25standard of subsection (d-20) of Section 1-75 of the Illinois 
26Power Agency Act. Such costs shall include the contract costs 
 
 
10400SB0025ham004- 777 -LRB104 16098 AAS 29398 a

1for the energy storage system resources and the prudent and 
2reasonable costs that the utility incurs as part of the 
3procurement processes and in implementing and complying with 
4plans and processes approved by the Commission under 
5subsection (d-20). The costs associated with the purchase of 
6energy storage system resources shall be allocated across all 
7retail customers in proportion to the amount of energy storage 
8system resources the utility procures for such customers 
9through a single, uniform cents per kilowatt-hour charge 
10applicable to such retail customers, which shall appear as a 
11separate line item on each customer's bill. Beginning June 1, 
122017, the electric utility shall be entitled to recover 
13through tariffed charges all of the costs associated with the 
14purchase of renewable energy resources to meet the renewable 
15energy resource standards of subsection (c) of Section 1-75 of 
16the Illinois Power Agency Act, under procurement plans as 
17approved in accordance with that Section and Section 16-111.5 
18of this Act. Such costs shall include the costs of procuring 
19the renewable energy resources, as well as the reasonable 
20costs that the utility incurs as part of the procurement 
21processes and to implement and comply with plans and processes 
22approved by the Commission under such Sections. The costs 
23associated with the purchase of renewable energy resources 
24shall be allocated across all retail customers in proportion 
25to the amount of renewable energy resources the utility 
26procures for such customers through a single, uniform cents 
 
 
10400SB0025ham004- 778 -LRB104 16098 AAS 29398 a

1per kilowatt-hour charge applicable to such retail customers, 
2which shall appear as a separate line item on each such 
3customer's bill. The credits, costs, and penalties associated 
4with the self-direct renewable portfolio standard compliance 
5program described in subparagraph (R) of paragraph (1) of 
6subsection (c) of Section 1-75 of the Illinois Power Agency 
7Act shall be allocated to approved eligible self-direct 
8customers by the utility in a cents per kilowatt-hour credit, 
9cost, or penalty, which shall appear as a separate line item on 
10each such customer's bill. 
11    Notwithstanding whether the Commission has approved the 
12initial long-term renewable resources procurement plan as of 
13June 1, 2017, an electric utility shall place new tariffed 
14charges into effect beginning with the June 2017 monthly 
15billing period, to the extent practicable, to begin recovering 
16the costs of procuring renewable energy resources, as those 
17charges are calculated under the limitations described in 
18subparagraph (E) of paragraph (1) of subsection (c) of Section 
191-75 of the Illinois Power Agency Act. Notwithstanding the 
20date on which the utility places such new tariffed charges 
21into effect, the utility shall be permitted to collect the 
22charges under such tariff as if the tariff had been in effect 
23beginning with the first day of the June 2017 monthly billing 
24period. For the delivery years commencing June 1, 2017, June 
251, 2018, June 1, 2019, and each delivery year thereafter, the 
26electric utility shall deposit into a separate interest 
 
 
10400SB0025ham004- 779 -LRB104 16098 AAS 29398 a

1bearing account of a financial institution the monies 
2collected under the tariffed charges. Money collected from 
3customers for the procurement of renewable energy resources in 
4a given delivery year may be spent by the utility for the 
5procurement of renewable resources over any of the following 5 
6delivery years, after which unspent money shall be credited 
7back to retail customers. The electric utility shall spend all 
8money collected in earlier delivery years that has not yet 
9been returned to customers, first, before spending money 
10collected in later delivery years. Any interest earned shall 
11be credited back to retail customers under the reconciliation 
12proceeding provided for in this subsection (k), provided that 
13the electric utility shall first be reimbursed from the 
14interest for the administrative costs that it incurs to 
15administer and manage the account. Any taxes due on the funds 
16in the account, or interest earned on it, will be paid from the 
17account or, if insufficient monies are available in the 
18account, from the monies collected under the tariffed charges 
19to recover the costs of procuring renewable energy resources. 
20Monies deposited in the account shall be subject to the 
21review, reconciliation, and true-up process described in this 
22subsection (k) that is applicable to the funds collected and 
23costs incurred for the procurement of renewable energy 
24resources.
25    The electric utility shall be entitled to recover all of 
26the costs identified in this subsection (k) through automatic 
 
 
10400SB0025ham004- 780 -LRB104 16098 AAS 29398 a

1adjustment clause tariffs applicable to all of the utility's 
2retail customers that allow the electric utility to adjust its 
3tariffed charges consistent with this subsection (k). The 
4determination as to whether any excess funds were collected 
5during a given delivery year for the purchase of renewable 
6energy resources, and the crediting of any excess funds back 
7to retail customers, shall not be made until after the close of 
8the delivery year, which will ensure that the maximum amount 
9of funds is available to implement the approved long-term 
10renewable resources procurement plan during a given delivery 
11year. The amount of excess funds eligible to be credited back 
12to retail customers shall be reduced by an amount equal to the 
13payment obligations required by any contracts entered into by 
14an electric utility under contracts described in subsection 
15(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
16Illinois Power Agency Act, even if such payments have not yet 
17been made and regardless of the delivery year in which those 
18payment obligations were incurred. Notwithstanding anything to 
19the contrary, including in tariffs authorized by this 
20subsection (k) in effect before the effective date of this 
21amendatory Act of the 102nd General Assembly, all unspent 
22funds as of May 31, 2021, excluding any funds credited to 
23customers during any utility billing cycle that commences 
24prior to the effective date of this amendatory Act of the 102nd 
25General Assembly, shall remain in the utility account and 
26shall on a first in, first out basis be used toward utility 
 
 
10400SB0025ham004- 781 -LRB104 16098 AAS 29398 a

1payment obligations under contracts described in subsection 
2(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
3Illinois Power Agency Act. The electric utility's collections 
4under such automatic adjustment clause tariffs to recover the 
5costs of renewable energy resources, zero emission credits 
6from zero emission facilities, energy storage resources, and 
7carbon mitigation credits from carbon-free energy resources 
8shall be subject to separate annual review, reconciliation, 
9and true-up against actual costs by the Commission under a 
10procedure that shall be specified in the electric utility's 
11automatic adjustment clause tariffs and that shall be approved 
12by the Commission in connection with its approval of such 
13tariffs. The procedure shall provide that any difference 
14between the electric utility's collections for energy storage 
15resources, zero emission credits, and carbon mitigation 
16credits under the automatic adjustment charges for an annual 
17period and the electric utility's actual costs of energy 
18storage resources, zero emission credits from zero emission 
19facilities, and carbon mitigation credits from carbon-free 
20energy resources for that same annual period shall be refunded 
21to or collected from, as applicable, the electric utility's 
22retail customers in subsequent periods.
23    Nothing in this subsection (k) is intended to affect, 
24limit, or change the right of the electric utility to recover 
25the costs associated with the procurement of renewable energy 
26resources for periods commencing before, on, or after June 1, 
 
 
10400SB0025ham004- 782 -LRB104 16098 AAS 29398 a

12017, as otherwise provided in the Illinois Power Agency Act. 
2    The funding available under this subsection (k), if any, 
3for the programs described under subsection (b) of Section 
41-56 of the Illinois Power Agency Act shall not reduce the 
5amount of funding for the programs described in subparagraph 
6(O) of paragraph (1) of subsection (c) of Section 1-75 of the 
7Illinois Power Agency Act. If funding is available under this 
8subsection (k) for programs described under subsection (b) of 
9Section 1-56 of the Illinois Power Agency Act, then the 
10long-term renewable resources plan shall provide for the 
11Agency to procure contracts in an amount that does not exceed 
12the funding, and the contracts approved by the Commission 
13shall be executed by the applicable utility or utilities. 
14    (l) A utility that has terminated any contract executed 
15under subsection (d-5) or (d-10) of Section 1-75 of the 
16Illinois Power Agency Act shall be entitled to recover any 
17remaining balance associated with the purchase of zero 
18emission credits prior to such termination, and such utility 
19shall also apply a credit to its retail customer bills in the 
20event of any over-collection. 
21    (m)(1) An electric utility that recovers its costs of 
22procuring zero emission credits from zero emission facilities 
23through a cents-per-kilowatthour charge under subsection (k) 
24of this Section shall be subject to the requirements of this 
25subsection (m). Notwithstanding anything to the contrary, such 
26electric utility shall, beginning on April 30, 2018, and each 
 
 
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1April 30 thereafter until April 30, 2026, calculate whether 
2any reduction must be applied to such cents-per-kilowatthour 
3charge that is paid by retail customers of the electric 
4utility that have opted out of subsections (a) through (j) of 
5Section 8-103B of this Act under subsection (l) of Section 
68-103B. Such charge shall be reduced for such customers for 
7the next delivery year commencing on June 1 based on the amount 
8necessary, if any, to limit the annual estimated average net 
9increase for the prior calendar year due to the future energy 
10investment costs to no more than 1.3% of 5.98 cents per 
11kilowatt-hour, which is the average amount paid per 
12kilowatthour for electric service during the year ending 
13December 31, 2015 by Illinois industrial retail customers, as 
14reported to the Edison Electric Institute. 
15    The calculations required by this subsection (m) shall be 
16made only once for each year, and no subsequent rate impact 
17determinations shall be made. 
18    (2) For purposes of this Section, "future energy 
19investment costs" shall be calculated by subtracting the 
20cents-per-kilowatthour charge identified in subparagraph (A) 
21of this paragraph (2) from the sum of the 
22cents-per-kilowatthour charges identified in subparagraph (B) 
23of this paragraph (2): 
24        (A) The cents-per-kilowatthour charge identified in 
25    the electric utility's tariff placed into effect under 
26    Section 8-103 of the Public Utilities Act that, on 
 
 
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1    December 1, 2016, was applicable to those retail customers 
2    that have opted out of subsections (a) through (j) of 
3    Section 8-103B of this Act under subsection (l) of Section 
4    8-103B. 
5        (B) The sum of the following cents-per-kilowatthour 
6    charges applicable to those retail customers that have 
7    opted out of subsections (a) through (j) of Section 8-103B 
8    of this Act under subsection (l) of Section 8-103B, 
9    provided that if one or more of the following charges has 
10    been in effect and applied to such customers for more than 
11    one calendar year, then each charge shall be equal to the 
12    average of the charges applied over a period that 
13    commences with the calendar year ending December 31, 2017 
14    and ends with the most recently completed calendar year 
15    prior to the calculation required by this subsection (m): 
16            (i) the cents-per-kilowatthour charge to recover 
17        the costs incurred by the utility under subsection 
18        (d-5) of Section 1-75 of the Illinois Power Agency 
19        Act, adjusted for any reductions required under this 
20        subsection (m); and
21            (ii) the cents-per-kilowatthour charge to recover 
22        the costs incurred by the utility under Section 
23        16-107.6 of the Public Utilities Act. 
24        If no charge was applied for a given calendar year 
25    under item (i) or (ii) of this subparagraph (B), then the 
26    value of the charge for that year shall be zero. 
 
 
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1    (3) If a reduction is required by the calculation 
2performed under this subsection (m), then the amount of the 
3reduction shall be multiplied by the number of years reflected 
4in the averages calculated under subparagraph (B) of paragraph 
5(2) of this subsection (m). Such reduction shall be applied to 
6the cents-per-kilowatthour charge that is applicable to those 
7retail customers that have opted out of subsections (a) 
8through (j) of Section 8-103B of this Act under subsection (l) 
9of Section 8-103B beginning with the next delivery year 
10commencing after the date of the calculation required by this 
11subsection (m). 
12    (4) The electric utility shall file a notice with the 
13Commission on May 1 of 2018 and each May 1 thereafter until May 
141, 2026 containing the reduction, if any, which must be 
15applied for the delivery year which begins in the year of the 
16filing. The notice shall contain the calculations made 
17pursuant to this Section. By October 1 of each year beginning 
18in 2018, each electric utility shall notify the Commission if 
19it appears, based on an estimate of the calculation required 
20in this subsection (m), that a reduction will be required in 
21the next year. 
22(Source: P.A. 102-662, eff. 9-15-21.)
 
23    (220 ILCS 5/16-108.19)
24    Sec. 16-108.19. Division of Integrated Distribution 
25Planning.
 
 
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1    (a) The Commission shall employ establish the Division of 
2Integrated Distribution Planning within the Bureau of Public 
3Utilities. The Division shall be staffed by no less than 13    
4professionals, including engineers, rate analysts, 
5accountants, policy analysts, utility research and analysis 
6analysts, cybersecurity analysts, informational technology 
7specialists, and lawyers, and other personnel deemed necessary 
8and appropriate by the Executive Director to review and 
9evaluate Integrated Grid Plans, updates to Integrated Grid 
10Plans, audits, and other duties as assigned. The personnel may 
11be organized or assigned into departments, bureaus, sections, 
12or divisions as determined by the Executive Director pursuant 
13to the authority granted under this Section by the Chief of the 
14Public Utilities Bureau.
15    (b) The Division of Integrated Distribution Planning shall 
16be established by January 1, 2022. 
17(Source: P.A. 102-662, eff. 9-15-21.)
 
18    (220 ILCS 5/16-108.30)
19    Sec. 16-108.30. Energy Transition Assistance Fund.
20    (a) The Energy Transition Assistance Fund is hereby 
21created as a special fund in the State treasury Treasury. The 
22Energy Transition Assistance Fund is authorized to receive 
23moneys collected pursuant to this Section. Subject to 
24appropriation, the Department of Commerce and Economic 
25Opportunity shall use moneys from the Energy Transition 
 
 
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1Assistance Fund consistent with the purposes of this Act.
2    (b) An electric utility serving more than 500,000 
3customers in the State shall assess an energy transition 
4assistance charge on all its retail customers for the Energy 
5Transition Assistance Fund. The utility's total charge shall 
6be set based upon the value determined by the Department of 
7Commerce and Economic Opportunity pursuant to subsection (d) 
8or (e), as applicable, of Section 605-1075 of the Department 
9of Commerce and Economic Opportunity Law of the Civil 
10Administrative Code of Illinois. For each utility, the charge 
11shall be recovered through a single, uniform cents per 
12kilowatt-hour charge applicable to all retail customers. For 
13each utility, the charge shall not exceed 1.45% 1.3% of the 
14amount paid per kilowatthour by eligible retail customers 
15during the year ending May 31, 2009. Beginning January 1, 
162028, the limitation shall be increased by an additional 0.636 
17percentage points of the amount paid per kilowatt-hour by 
18eligible retail customers during the year ending May 31, 2009, 
19which would collect the equivalent of the average annual 
20budget of the programs administered by the utilities under 
21Section 45 of the Electric Vehicle Act for the years 2026 
22through 2028.    
23    (c) Within 75 days of the effective date of this 
24amendatory Act of the 102nd General Assembly, each electric 
25utility serving more than 500,000 customers in the State shall 
26file with the Illinois Commerce Commission tariffs 
 
 
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1incorporating the energy transition assistance charge in other 
2charges stated in such tariffs, which energy transition 
3assistance charges shall become effective no later than the 
4beginning of the first billing cycle that begins on or after 
5January 1, 2022. Each electric utility serving more than 
6500,000 customers in the State shall, prior to the beginning 
7of each calendar year starting with calendar year 2023, file 
8with the Illinois Commerce Commission tariff revisions to 
9incorporate annual revisions to the energy transition 
10assistance charge as prescribed by the Department of Commerce 
11and Economic Opportunity pursuant to Section 605-1075 of the 
12Department of Commerce and Economic Opportunity Law of the 
13Civil Administrative Code of Illinois so that such revision 
14becomes effective no later than the beginning of the first 
15billing cycle in each respective year.
16    (d) The energy transition assistance charge shall be 
17considered a charge for public utility service.
18    (e) By the 20th day of the month following the month in 
19which the charges imposed by this Section were collected, each 
20electric utility serving more than 500,000 customers in the 
21State shall remit to Department of Revenue all moneys received 
22as payment of the energy transition assistance charge on a 
23return prescribed and furnished by the Department of Revenue 
24showing such information as the Department of Revenue may 
25reasonably require. If a customer makes a partial payment, a 
26public utility may apply such partial payments first to 
 
 
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1amounts owed to the utility. No customer may be subjected to 
2disconnection of his or her utility service for failure to pay 
3the energy transition assistance charge.
4    If any payment provided for in this subsection exceeds the 
5electric utility's liabilities under this Act, as shown on an 
6original return, the Department may authorize the electric 
7utility to credit such excess payment against liability 
8subsequently to be remitted to the Department under this Act, 
9in accordance with reasonable rules adopted by the Department.
10    All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e, 
115f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13 
12of the Retailers' Occupation Tax Act that are not inconsistent 
13with this Act apply, as far as practicable, to the charge 
14imposed by this Act to the same extent as if those provisions 
15were included in this Act. References in the incorporated 
16Sections of the Retailers' Occupation Tax Act to retailers, to 
17sellers, or to persons engaged in the business of selling 
18tangible personal property mean persons required to remit the 
19charge imposed under this Act.
20    (f) The Department of Revenue shall deposit into the 
21Energy Transition Assistance Fund all moneys remitted to it in 
22accordance with this Section.
23    (g) The Department of Revenue may establish such rules as 
24it deems necessary to implement this Section.
25    (h) The Department of Commerce and Economic Opportunity 
26may establish such rules as it deems necessary to implement 
 
 
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1this Section. 
2(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
3    (220 ILCS 5/16-111.5)
4    Sec. 16-111.5. Provisions relating to procurement.
5    (a) An electric utility that on December 31, 2005 served 
6at least 100,000 customers in Illinois shall procure power and 
7energy for its eligible retail customers in accordance with 
8the applicable provisions set forth in Section 1-75 of the 
9Illinois Power Agency Act and this Section. Beginning with the 
10delivery year commencing on June 1, 2017, such electric 
11utility shall also procure zero emission credits from zero 
12emission facilities in accordance with the applicable 
13provisions set forth in Section 1-75 of the Illinois Power 
14Agency Act, and, for years beginning on or after June 1, 2017, 
15the utility shall procure renewable energy resources in 
16accordance with the applicable provisions set forth in Section 
171-75 of the Illinois Power Agency Act and this Section. 
18Beginning with the delivery year commencing on June 1, 2022, 
19an electric utility serving over 3,000,000 customers shall 
20also procure carbon mitigation credits from carbon-free energy 
21resources in accordance with the applicable provisions set 
22forth in Section 1-75 of the Illinois Power Agency Act and this 
23Section. Beginning with the delivery year commencing on June 
241, 2026, an electric utility serving more than 300,000 
25customers in the State as of January 1, 2019 shall also procure 
 
 
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1energy storage resources in accordance with the applicable 
2provisions of subsection (d-20) of Section 1-75 of the 
3Illinois Power Agency Act and this Section. A small 
4multi-jurisdictional electric utility that on December 31, 
52005 served less than 100,000 customers in Illinois may elect 
6to procure power and energy for all or a portion of its 
7eligible Illinois retail customers in accordance with the 
8applicable provisions set forth in this Section and Section 
91-75 of the Illinois Power Agency Act. This Section shall not 
10apply to a small multi-jurisdictional utility until such time 
11as a small multi-jurisdictional utility requests the Illinois 
12Power Agency to prepare a procurement plan for its eligible 
13retail customers. "Eligible retail customers" for the purposes 
14of this Section means those retail customers that purchase 
15power and energy from the electric utility under fixed-price 
16bundled service tariffs, other than those retail customers 
17whose service is declared or deemed competitive under Section 
1816-113 and those other customer groups specified in this 
19Section, including self-generating customers, customers 
20electing hourly pricing, or those customers who are otherwise 
21ineligible for fixed-price bundled tariff service. Except as 
22otherwise provided for in subsection (b-10), for For those 
23customers that are excluded from the procurement plan's 
24electric supply service requirements, and the utility shall 
25procure any supply requirements, including capacity, ancillary 
26services, and hourly priced energy, in the applicable markets 
 
 
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1as needed to serve those customers, provided that the utility 
2may include in its procurement plan load requirements for the 
3load that is associated with those retail customers whose 
4service has been declared or deemed competitive pursuant to 
5Section 16-113 of this Act to the extent that those customers 
6are purchasing power and energy during one of the transition 
7periods identified in subsection (b) of Section 16-113 of this 
8Act. 
9    (b) A procurement plan shall be prepared for each electric 
10utility consistent with the applicable requirements of the 
11Illinois Power Agency Act and this Section. For purposes of 
12this Section, Illinois electric utilities that are affiliated 
13by virtue of a common parent company are considered to be a 
14single electric utility. Small multi-jurisdictional utilities 
15may request a procurement plan for a portion of or all of its 
16Illinois load. Each procurement plan shall analyze the 
17projected balance of supply and demand for those retail 
18customers to be included in the plan's electric supply service 
19requirements over a 5-year period, with the first planning 
20year beginning on June 1 of the year following the year in 
21which the plan is filed. The plan shall specifically identify 
22the wholesale products to be procured following plan approval, 
23and shall follow all the requirements set forth in the Public 
24Utilities Act and all applicable State and federal laws, 
25statutes, rules, or regulations, as well as Commission orders. 
26Nothing in this Section precludes consideration of contracts 
 
 
10400SB0025ham004- 793 -LRB104 16098 AAS 29398 a

1longer than 5 years and related forecast data. Unless 
2specified otherwise in this Section, in the procurement plan 
3or in the implementing tariff, any procurement occurring in 
4accordance with this plan shall be competitively bid through a 
5request for proposals process. Approval and implementation of 
6the procurement plan shall be subject to review and approval 
7by the Commission according to the provisions set forth in 
8this Section. A procurement plan shall include each of the 
9following components:
10        (1) Hourly load analysis. This analysis shall include:
11            (i) multi-year historical analysis of hourly 
12        loads;
13            (ii) switching trends and competitive retail 
14        market analysis;
15            (iii) known or projected changes to future loads; 
16        and
17            (iv) growth forecasts by customer class.
18        (2) Analysis of the impact of any demand side and 
19    renewable energy initiatives. This analysis shall include:
20            (i) the impact of demand response programs and 
21        energy efficiency programs, both current and 
22        projected; for small multi-jurisdictional utilities, 
23        the impact of demand response and energy efficiency 
24        programs approved pursuant to Section 8-408 of this 
25        Act, both current and projected; and
26            (ii) supply side needs that are projected to be 
 
 
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1        offset by purchases of renewable energy resources, if 
2        any.
3        (3) A plan for meeting the expected load requirements 
4    that will not be met through preexisting contracts. This 
5    plan shall include:
6            (i) definitions of the different Illinois retail 
7        customer classes for which supply is being purchased;
8            (ii) the proposed mix of demand-response products 
9        for which contracts will be executed during the next 
10        year. For small multi-jurisdictional electric 
11        utilities that on December 31, 2005 served fewer than 
12        100,000 customers in Illinois, these shall be defined 
13        as demand-response products offered in an energy 
14        efficiency plan approved pursuant to Section 8-408 of 
15        this Act. The cost-effective demand-response measures 
16        shall be procured whenever the cost is lower than 
17        procuring comparable capacity products, provided that 
18        such products shall: 
19                (A) be procured by a demand-response provider 
20            from those retail customers included in the plan's 
21            electric supply service requirements;
22                (B) at least satisfy the demand-response 
23            requirements of the regional transmission 
24            organization market in which the utility's service 
25            territory is located, including, but not limited 
26            to, any applicable capacity or dispatch 
 
 
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1            requirements;
2                (C) provide for customers' participation in 
3            the stream of benefits produced by the 
4            demand-response products;
5                (D) provide for reimbursement by the 
6            demand-response provider of the utility for any 
7            costs incurred as a result of the failure of the 
8            supplier of such products to perform its 
9            obligations thereunder; and
10                (E) meet the same credit requirements as apply 
11            to suppliers of capacity, in the applicable 
12            regional transmission organization market; 
13            (iii) monthly forecasted system supply 
14        requirements, including expected minimum, maximum, and 
15        average values for the planning period;
16            (iv) the proposed mix and selection of standard 
17        wholesale products for which contracts will be 
18        executed during the next year, separately or in 
19        combination, to meet that portion of its load 
20        requirements not met through pre-existing contracts, 
21        including but not limited to monthly 5 x 16 peak period 
22        block energy, monthly off-peak wrap energy, monthly 7 
23        x 24 energy, annual 5 x 16 energy, other standardized 
24        energy or capacity products designed to provide 
25        eligible retail customer benefits from commercially 
26        deployed advanced technologies including but not 
 
 
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1        limited to high voltage direct current converter 
2        stations, as such term is defined in Section 1-10 of 
3        the Illinois Power Agency Act, whether or not such 
4        product is currently available in wholesale markets, 
5        annual off-peak wrap energy, annual 7 x 24 energy, 
6        monthly capacity, annual capacity, peak load capacity 
7        obligations, capacity purchase plan, and ancillary 
8        services;
9            (v) proposed term structures for each wholesale 
10        product type included in the proposed procurement plan 
11        portfolio of products; and
12            (vi) an assessment of the price risk, load 
13        uncertainty, and other factors that are associated 
14        with the proposed procurement plan; this assessment, 
15        to the extent possible, shall include an analysis of 
16        the following factors: contract terms, time frames for 
17        securing products or services, fuel costs, weather 
18        patterns, transmission costs, market conditions, and 
19        the governmental regulatory environment; the proposed 
20        procurement plan shall also identify alternatives for 
21        those portfolio measures that are identified as having 
22        significant price risk and mitigation in the form of 
23        additional retail customer and ratepayer price, 
24        reliability, and environmental benefits from 
25        standardized energy products delivered from 
26        commercially deployed advanced technologies, 
 
 
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1        including, but not limited to, high voltage direct 
2        current converter stations, as such term is defined in 
3        Section 1-10 of the Illinois Power Agency Act, whether 
4        or not such product is currently available in 
5        wholesale markets.
6        (4) Proposed procedures for balancing loads. The 
7    procurement plan shall include, for load requirements 
8    included in the procurement plan, the process for (i) 
9    hourly balancing of supply and demand and (ii) the 
10    criteria for portfolio re-balancing in the event of 
11    significant shifts in load.
12        (5) Long-Term Renewable Resources Procurement Plan. 
13    The Agency shall prepare a long-term renewable resources 
14    procurement plan for the procurement of renewable energy 
15    credits under Sections 1-56 and 1-75 of the Illinois Power 
16    Agency Act for delivery beginning in the 2017 delivery 
17    year.
18            (i) The initial long-term renewable resources 
19        procurement plan and all subsequent revisions shall be 
20        subject to review and approval by the Commission. For 
21        the purposes of this Section, "delivery year" has the 
22        same meaning as in Section 1-10 of the Illinois Power 
23        Agency Act. For purposes of this Section, "Agency" 
24        shall mean the Illinois Power Agency.
25            (ii) The long-term renewable resources planning 
26        process shall be conducted as follows:
 
 
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1                (A) Electric utilities shall provide a range 
2            of load forecasts to the Illinois Power Agency 
3            within 45 days of the Agency's request for 
4            forecasts, which request shall specify the length 
5            and conditions for the forecasts including, but 
6            not limited to, the quantity of distributed 
7            generation expected to be interconnected for each 
8            year.
9                (B) The Agency shall publish for comment the 
10            initial long-term renewable resources procurement 
11            plan no later than 120 days after the effective 
12            date of this amendatory Act of the 99th General 
13            Assembly and shall review, and may revise, the 
14            plan at least every 2 years thereafter. To the 
15            extent practicable, the Agency shall review and 
16            propose any revisions to the long-term renewable 
17            energy resources procurement plan in conjunction 
18            with the Agency's other planning and approval 
19            processes conducted under this Section. Plans may 
20            be released on separate dates, but the Agency 
21            shall, to the extent practicable, release both 
22            plans across a 30-day period. The initial 
23            long-term renewable resources procurement plan 
24            shall:
25                    (aa) Identify the procurement programs and 
26                competitive procurement events consistent with 
 
 
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1                the applicable requirements of the Illinois 
2                Power Agency Act and shall be designed to 
3                achieve the goals set forth in subsection (c) 
4                of Section 1-75 of that Act.
5                    (bb) Include a schedule for procurements 
6                for renewable energy credits from 
7                utility-scale wind projects, utility-scale 
8                solar projects, and brownfield site 
9                photovoltaic projects consistent with 
10                subparagraph (G) of paragraph (1) of 
11                subsection (c) of Section 1-75 of the Illinois 
12                Power Agency Act.
13                    (cc) Identify the process whereby the 
14                Agency will submit to the Commission for 
15                review and approval the proposed contracts to 
16                implement the programs required by such plan.
17                If so authorized by the Commission in its 
18            order approving the procurement plan, the 
19            procurement plan shall provide that small 
20            multi-jurisdictional electric utilities that, on 
21            December 31, 2005, served fewer than 100,000 
22            customers in Illinois shall, in lieu of serving as 
23            counterparties to contracts for the delivery of 
24            renewable energy credits, instead provide an 
25            amount equivalent to the contracts for the 
26            delivery of renewable energy credits in 
 
 
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1            collections to utilities that served at least 
2            100,000 customers in Illinois as a compliance 
3            payment for the procurement of additional 
4            renewable energy credits to satisfy that small 
5            multi-jurisdictional electric utility's 
6            obligation for compliance with the goals set forth 
7            in subsection (c) of Section 1-75 of the Illinois 
8            Power Agency Act. This authorization may include 
9            the transfer of existing contract obligations.    
10                Copies of the initial long-term renewable 
11            resources procurement plan and all subsequent 
12            revisions shall be posted and made publicly 
13            available on the Agency's and Commission's 
14            websites, and copies shall also be provided to 
15            each affected electric utility. An affected 
16            utility and other interested parties shall have 45 
17            days following the date of posting to provide 
18            comment to the Agency on the initial long-term 
19            renewable resources procurement plan and all 
20            subsequent revisions. All comments submitted to 
21            the Agency shall be specific, supported by data or 
22            other detailed analyses, and, if objecting to all 
23            or a portion of the procurement plan, accompanied 
24            by specific alternative wording or proposals. All 
25            comments shall be posted on the Agency's and 
26            Commission's websites. During this 45-day comment 
 
 
10400SB0025ham004- 801 -LRB104 16098 AAS 29398 a

1            period, the Agency shall hold at least one virtual 
2            or in-person public hearing for within each 
3            utility's service area that is subject to the 
4            requirements of this paragraph (5) for the purpose 
5            of receiving public comment. Within 21 days 
6            following the end of the 45-day review period, the 
7            Agency may revise the long-term renewable 
8            resources procurement plan based on the comments 
9            received and shall file the plan with the 
10            Commission for review and approval.
11                (C) Within 14 days after the filing of the 
12            initial long-term renewable resources procurement 
13            plan or any subsequent revisions, any person 
14            objecting to the plan may file an objection with 
15            the Commission. Within 21 days after the filing of 
16            the plan, the Commission shall determine whether a 
17            hearing is necessary. The Commission shall enter 
18            its order confirming or modifying the initial 
19            long-term renewable resources procurement plan or 
20            any subsequent revisions within 120 days after the 
21            filing of the plan by the Illinois Power Agency.
22                (D) The Commission shall approve the initial 
23            long-term renewable resources procurement plan and 
24            any subsequent revisions, including expressly the 
25            forecast used in the plan and taking into account 
26            that funding will be limited to the amount of 
 
 
10400SB0025ham004- 802 -LRB104 16098 AAS 29398 a

1            revenues actually collected by the utilities, if 
2            the Commission determines that the plan will 
3            reasonably and prudently accomplish the 
4            requirements of Section 1-56 and subsection (c) of 
5            Section 1-75 of the Illinois Power Agency Act. The 
6            Commission shall also approve the process for the 
7            submission, review, and approval of the proposed 
8            contracts to procure renewable energy credits or 
9            implement the programs authorized by the 
10            Commission pursuant to a long-term renewable 
11            resources procurement plan approved under this 
12            Section.
13                In approving any long-term renewable resources 
14            procurement plan after the effective date of this 
15            amendatory Act of the 102nd General Assembly, the 
16            Commission shall approve or modify the Agency's 
17            proposal for minimum equity standards pursuant to 
18            subsection (c-10) of Section 1-75 of the Illinois 
19            Power Agency Act. The Commission shall consider 
20            any analysis performed by the Agency in developing 
21            its proposal, including past performance, 
22            availability of equity eligible contractors, and 
23            availability of equity eligible persons at the 
24            time the long-term renewable resources procurement 
25            plan is approved. 
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 long-term renewable 
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 
7        the contract or contracts under the process authorized 
8        by the Commission in item (D) of subparagraph (ii) of 
9        paragraph (5) of this subsection (b) and the third 
10        party and the Agency or utility, as applicable, have 
11        executed the contract. For those renewable energy 
12        credits subject to procurement through a competitive 
13        bid process under the plan or under the initial 
14        forward procurements for wind and solar resources 
15        described in subparagraph (G) of paragraph (1) of 
16        subsection (c) of Section 1-75 of the Illinois Power 
17        Agency Act, the Agency shall follow the procurement 
18        process specified in the provisions relating to 
19        electricity procurement in subsections (e) through (i) 
20        of this Section.
21            (iv) An electric utility shall recover its costs 
22        associated with the procurement of renewable energy 
23        credits under this Section and pursuant to subsection 
24        (c-5) of Section 1-75 of the Illinois Power Agency Act 
25        through an automatic adjustment clause tariff under 
26        subsection (k) or a tariff pursuant to subsection 
 
 
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1        (i-5), as applicable, of Section 16-108 of this Act. A 
2        utility shall not be required to advance any payment 
3        or pay any amounts under this Section that exceed the 
4        actual amount of revenues collected by the utility 
5        under paragraph (6) of subsection (c) of Section 1-75 
6        of the Illinois Power Agency Act, subsection (c-5) of 
7        Section 1-75 of the Illinois Power Agency Act, and 
8        subsection (k) or subsection (i-5), as applicable, of 
9        Section 16-108 of this Act, and contracts executed 
10        under this Section shall expressly incorporate this 
11        limitation.
12            (v) For the public interest, safety, and welfare, 
13        the Agency and the Commission may adopt rules to carry 
14        out the provisions of this Section on an emergency 
15        basis immediately following the effective date of this 
16        amendatory Act of the 99th General Assembly.
17            (vi) On or before July 1 of each year, the 
18        Commission shall hold an informal hearing for the 
19        purpose of receiving comments on the prior year's 
20        procurement process and any recommendations for 
21        change. 
22        (6) Energy Storage System Resources Procurement Plan. 
23    The Agency shall prepare an energy storage system 
24    resources procurement plan for the procurement of energy 
25    storage system resources in compliance with this Section 
26    and subsection (d-20) of Section 1-75 of the Illinois 
 
 
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1    Power Agency Act.
2            (i) The initial energy storage system resources 
3        procurement plan and all subsequent revisions shall be 
4        subject to review and approval by the Commission. For 
5        the purposes of this paragraph (6), "delivery year" 
6        has the meaning given to that term in Section 1-10 of 
7        the Illinois Power Agency Act, and "Agency" means the 
8        Illinois Power Agency.
9            (ii) The energy storage system resources 
10        procurement planning process shall be conducted as 
11        follows:
12                (A) The Agency shall publish for comment the 
13            initial energy storage system resources 
14            procurement plan no later than June 1, 2027 and 
15            may revise the plan at least every 2 years 
16            thereafter. To the extent practicable, the Agency 
17            shall review and propose any revisions to the 
18            energy storage system resources procurement plan 
19            in conjunction with the Agency's long-term 
20            renewable resources procurement plan. The initial 
21            energy storage system resources plan shall:
22                    (aa) include a schedule for procurements 
23                for energy storage system resources consistent 
24                with subsection (d-20) of Section 1-75 of the 
25                Illinois Power Agency Act and the integrated 
26                resource planning process outlined in Section 
 
 
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1                16-202; and
2                    (bb) identify the process whereby the 
3                Agency will submit to the Commission for 
4                review and approval the proposed contracts to 
5                implement the programs required by the plan.
6                Copies of the initial energy storage system 
7            resources procurement plan and all subsequent 
8            revisions shall be posted and made publicly 
9            available on the Agency's and Commission's 
10            websites, and copies shall also be provided to 
11            each affected electric utility. An affected 
12            utility and other interested parties shall have 45 
13            days after the date of posting to provide comment 
14            to the Agency on the initial storage system 
15            resources procurement plan and all subsequent 
16            revisions. All comments shall be posted on the 
17            Agency's and the Commission's websites.
18                (B) The Commission shall approve the initial 
19            energy storage system resources procurement plan 
20            and any subsequent revisions if the Commission 
21            determines that the plan will reasonably and 
22            prudently accomplish the requirements of 
23            subsection (d-20) of Section 1-75 of the Illinois 
24            Power Agency Act. The Commission shall also 
25            approve the process for the submission, review, 
26            and approval of the proposed contracts to procure 
 
 
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1            energy storage system resources or implement the 
2            programs authorized by the Commission pursuant to 
3            an energy storage system resources procurement 
4            plan approved under this Section.
5            (iii) The Agency or third parties contracted by 
6        the Agency shall implement all programs authorized by 
7        the Commission in an approved energy storage system 
8        resources procurement plan without further review and 
9        approval by the Commission. Third parties shall not 
10        begin implementing any programs or receive any payment 
11        under this Section until the Commission has approved a 
12        contract under the energy storage system resources 
13        procurement process under this Section.
14            (iv) An electric utility shall recover its prudent 
15        and reasonable costs associated with the procurement 
16        of energy storage system resources procurements under 
17        this Section and under subsection (d-20) of Section 
18        1-75 of the Illinois Power Agency Act through an 
19        automatic adjustment clause tariff under subsection 
20        (k) of Section 16-108.    
21    (b-5) An electric utility that as of January 1, 2019 
22served more than 300,000 retail customers in this State shall 
23purchase renewable energy credits from new renewable energy 
24facilities constructed at or adjacent to the sites of 
25coal-fueled electric generating facilities in this State in 
26accordance with subsection (c-5) of Section 1-75 of the 
 
 
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1Illinois Power Agency Act and shall purchase energy storage 
2credits, or other services as applicable, for energy storage 
3system resources in accordance with subsection (d-20) of 
4Section 1-75 of the Illinois Power Agency Act. Except as 
5expressly provided in this Section, the plans and procedures 
6for such procurements shall not be included in the procurement 
7plans provided for in this Section, but rather shall be 
8conducted and implemented solely in accordance with subsection 
9(c-5) of Section 1-75 of the Illinois Power Agency Act.
10    (b-10) Beginning with the procurement plan for the 
11delivery year commencing on June 1, 2027, in recognition of 
12the potential need to facilitate additional supply to address 
13any resource adequacy challenges through a stable and 
14competitively neutral cost allocation mechanism, upon an 
15identification of need by the Commission in the resource 
16adequacy report prepared pursuant to subsection (o) of Section 
179.15 of the Environmental Protection Act, and as such need is 
18updated by the integrated resource planning process outlined 
19in subsection (b), the procurement plan shall also include the 
20procurement of energy, capacity, environmental attributes, 
21resource adequacy attributes, or some combination thereof 
22intended to serve all retail customers. Any procurements 
23proposed under this subsection (b-10) shall feature long-term 
24contracts, shall be structured to facilitate new and additive 
25supply resources, and shall be sized to ensure that the 
26substantial majority of any load-serving entity's supply 
 
 
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1portfolio is not composed of contracts awarded under this 
2subsection (b-10). Any procurement should consider the value 
3of higher capacity resources that aid in resource adequacy. 
4The Agency shall propose contract structures that do not 
5create contractual obligations on utilities that are not 
6contingent on full and timely cost recovery, that avoid 
7negative financial impacts on the utilities, and that are 
8implemented through contracts that are agreed upon by the 
9utilities.
10        (1) Facilities eligible for long-term contracts under 
11    this subsection (b-10) must be new clean energy resources, 
12    as defined in Section 1-10 of the Illinois Power Agency 
13    Act, including clean generation associated high voltage 
14    direct current transmission facilities, and must qualify 
15    as an accredited capacity resource within the service 
16    areas of PJM Interconnection, LLC, or Midcontinent 
17    Independent System Operator, Inc. For purposes of this 
18    subsection (b-10), "new" means energized on or after the 
19    effective date of this amendatory Act of the 104th General 
20    Assembly.
21        (2) Contracts may take the form of a sourcing 
22    agreement, power purchase agreement, or other instrument 
23    as determined by the Commission in approving the plan, and 
24    may feature fixed or variable pricing structures, 
25    including utilization of a contract for differences in 
26    pricing structure. Contracts may feature both electric 
 
 
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1    utilities and alternative retail electric suppliers as 
2    counterparties. In approving the contract structure 
3    utilized for any contract awards made pursuant to this 
4    subsection (b-10), the Commission shall prioritize 
5    structures that ensure stable, reliable, and competitively 
6    neutral allocations of costs and responsibilities.
7        (3) Purchases made under contracts awarded through 
8    this subsection (b-10) shall be funded in a competitively 
9    neutral manner as determined by the Commission in 
10    approving the plan. To meet contract obligations, the 
11    Commission may order collections from all retail customers 
12    or from all load-serving entities, including alternative 
13    retail electric suppliers as defined in Section 16-102 of 
14    this Act, as a means of ensuring a fair and competitively 
15    neutral allocation of contract costs. In establishing 
16    collections, the Agency may propose and the Commission may 
17    approve adjustments for load-serving entities that have 
18    contracts entered into before the effective date of this 
19    amendatory Act of the 104th General Assembly for energy, 
20    capacity, or environmental attributes.
21        (4) The Agency may propose and the Commission may 
22    approve additional terms, conditions, and requirements 
23    applicable to this procurement process through development 
24    and approval of the Agency's annual electricity 
25    procurement plan.
26        (5) The manner and form for developing contracts, 
 
 
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1    qualifying potential counterparties, and awarding 
2    contracts shall be proposed as part of the annual 
3    electricity procurement plan described in this subsection 
4    (b-10). However, to the extent practicable, the proposed 
5    approach for contract development and award should 
6    endeavor to follow the provisions of subsections (c) and 
7    (e) through (i) of this Section.
8        (6) As further outlined in Section 16-115A, compliance 
9    with any procurement process proposed under this 
10    subsection (b-10) shall be considered a condition of 
11    service for alternative retail electric suppliers.    
12    (c) The provisions of this subsection (c) shall not apply 
13to procurements conducted pursuant to subsection (c-5) of 
14Section 1-75 of the Illinois Power Agency Act. However, the 
15Agency may retain a procurement administrator to assist the 
16Agency in planning and carrying out the procurement events and 
17implementing the other requirements specified in such 
18subsection (c-5) of Section 1-75 of the Illinois Power Agency 
19Act, with the costs incurred by the Agency for the procurement 
20administrator to be recovered through fees charged to 
21applicants for selection to sell and deliver renewable energy 
22credits to electric utilities pursuant to subsection (c-5) of 
23Section 1-75 of the Illinois Power Agency Act. The procurement 
24process set forth in Section 1-75 of the Illinois Power Agency 
25Act and subsection (e) of this Section shall be administered 
26by a procurement administrator and monitored by a procurement 
 
 
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1monitor.
2        (1) The procurement administrator shall:
3            (i) design the final procurement process in 
4        accordance with Section 1-75 of the Illinois Power 
5        Agency Act and subsection (e) of this Section 
6        following Commission approval of the procurement plan;
7            (ii) develop benchmarks in accordance with 
8        subsection (e)(3) to be used to evaluate bids; these 
9        benchmarks shall be submitted to the Commission for 
10        review and approval on a confidential basis prior to 
11        the procurement event;
12            (iii) serve as the interface between the electric 
13        utility and suppliers;
14            (iv) manage the bidder pre-qualification and 
15        registration process;
16            (v) obtain the electric utilities' agreement to 
17        the final form of all supply contracts and credit 
18        collateral agreements;
19            (vi) administer the request for proposals process;
20            (vii) have the discretion to negotiate to 
21        determine whether bidders are willing to lower the 
22        price of bids that meet the benchmarks approved by the 
23        Commission; any post-bid negotiations with bidders 
24        shall be limited to price only and shall be completed 
25        within 24 hours after opening the sealed bids and 
26        shall be conducted in a fair and unbiased manner; in 
 
 
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1        conducting the negotiations, there shall be no 
2        disclosure of any information derived from proposals 
3        submitted by competing bidders; if information is 
4        disclosed to any bidder, it shall be provided to all 
5        competing bidders;
6            (viii) maintain confidentiality of supplier and 
7        bidding information in a manner consistent with all 
8        applicable laws, rules, regulations, and tariffs;
9            (ix) submit a confidential report to the 
10        Commission recommending acceptance or rejection of 
11        bids;
12            (x) notify the utility of contract counterparties 
13        and contract specifics; and
14            (xi) administer related contingency procurement 
15        events.
16        (2) The procurement monitor, who shall be retained by 
17    the Commission, shall:
18            (i) monitor interactions among the procurement 
19        administrator, suppliers, and utility;
20            (ii) monitor and report to the Commission on the 
21        progress of the procurement process;
22            (iii) provide an independent confidential report 
23        to the Commission regarding the results of the 
24        procurement event;
25            (iv) assess compliance with the procurement plans 
26        approved by the Commission for each utility that on 
 
 
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1        December 31, 2005 provided electric service to at 
2        least 100,000 customers in Illinois and for each small 
3        multi-jurisdictional utility that on December 31, 2005 
4        served less than 100,000 customers in Illinois;
5            (v) preserve the confidentiality of supplier and 
6        bidding information in a manner consistent with all 
7        applicable laws, rules, regulations, and tariffs;
8            (vi) provide expert advice to the Commission and 
9        consult with the procurement administrator regarding 
10        issues related to procurement process design, rules, 
11        protocols, and policy-related matters; and
12            (vii) consult with the procurement administrator 
13        regarding the development and use of benchmark 
14        criteria, standard form contracts, credit policies, 
15        and bid documents.
16    (d) Except as provided in subsection (j), the planning 
17process shall be conducted as follows:
18        (1) Beginning in 2008, each Illinois utility procuring 
19    power pursuant to this Section shall annually provide a 
20    range of load forecasts to the Illinois Power Agency by 
21    July 15 of each year, or such other date as may be required 
22    by the Commission or Agency. The load forecasts shall 
23    cover the 5-year procurement planning period for the next 
24    procurement plan and shall include hourly data 
25    representing a high-load, low-load, and expected-load 
26    scenario for the load of those retail customers included 
 
 
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1    in the plan's electric supply service requirements. The 
2    utility shall provide supporting data and assumptions for 
3    each of the scenarios. 
4        (2) Beginning in 2008, the Illinois Power Agency shall 
5    prepare a procurement plan by August 15th of each year, or 
6    such other date as may be required by the Commission. The 
7    procurement plan shall identify the portfolio of 
8    demand-response and power and energy products to be 
9    procured. Cost-effective demand-response measures shall be 
10    procured as set forth in item (iii) of subsection (b) of 
11    this Section. Copies of the procurement plan shall be 
12    posted and made publicly available on the Agency's and 
13    Commission's websites, and copies shall also be provided 
14    to each affected electric utility. An affected utility 
15    shall have 30 days following the date of posting to 
16    provide comment to the Agency on the procurement plan. 
17    Other interested entities also may comment on the 
18    procurement plan. All comments submitted to the Agency 
19    shall be specific, supported by data or other detailed 
20    analyses, and, if objecting to all or a portion of the 
21    procurement plan, accompanied by specific alternative 
22    wording or proposals. All comments shall be posted on the 
23    Agency's and Commission's websites. During this 30-day 
24    comment period, the Agency shall hold at least one virtual 
25    or in-person public hearing for within each utility's 
26    service area for the purpose of receiving public comment 
 
 
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1    on the procurement plan. Within 14 days following the end 
2    of the 30-day review period, the Agency shall revise the 
3    procurement plan as necessary based on the comments 
4    received and file the procurement plan with the Commission 
5    and post the procurement plan on the websites.
6        (3) Within 5 days after the filing of the procurement 
7    plan, any person objecting to the procurement plan shall 
8    file an objection with the Commission. Within 10 days 
9    after the filing, the Commission shall determine whether a 
10    hearing is necessary. The Commission shall enter its order 
11    confirming or modifying the procurement plan within 90 
12    days after the filing of the procurement plan by the 
13    Illinois Power Agency.
14        (4) The Commission shall approve the procurement plan, 
15    including expressly the forecast used in the procurement 
16    plan, if the Commission determines that it will ensure 
17    adequate, reliable, affordable, efficient, and 
18    environmentally sustainable electric service at the lowest 
19    total cost over time, taking into account any benefits of 
20    price stability.
21        (4.5) The Commission shall review the Agency's 
22    recommendations for the selection of applicants to enter 
23    into long-term contracts for the sale and delivery of 
24    renewable energy credits from new renewable energy 
25    facilities to be constructed at or adjacent to the sites 
26    of coal-fueled electric generating facilities in this 
 
 
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1    State in accordance with the provisions of subsection 
2    (c-5) of Section 1-75 of the Illinois Power Agency Act, 
3    and shall approve the Agency's recommendations if the 
4    Commission determines that the applicants recommended by 
5    the Agency for selection, the proposed new renewable 
6    energy facilities to be constructed, the amounts of 
7    renewable energy credits to be delivered pursuant to the 
8    contracts, and the other terms of the contracts, are 
9    consistent with the requirements of subsection (c-5) of 
10    Section 1-75 of the Illinois Power Agency Act. 
11    (e) The procurement process shall include each of the 
12following components:
13        (1) Solicitation, pre-qualification, and registration 
14    of bidders. The procurement administrator shall 
15    disseminate information to potential bidders to promote a 
16    procurement event, notify potential bidders that the 
17    procurement administrator may enter into a post-bid price 
18    negotiation with bidders that meet the applicable 
19    benchmarks, provide supply requirements, and otherwise 
20    explain the competitive procurement process. In addition 
21    to such other publication as the procurement administrator 
22    determines is appropriate, this information shall be 
23    posted on the Illinois Power Agency's and the Commission's 
24    websites. The procurement administrator shall also 
25    administer the prequalification process, including 
26    evaluation of credit worthiness, compliance with 
 
 
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1    procurement rules, and agreement to the standard form 
2    contract developed pursuant to paragraph (2) of this 
3    subsection (e). The procurement administrator shall then 
4    identify and register bidders to participate in the 
5    procurement event.
6        (2) Standard contract forms and credit terms and 
7    instruments. The procurement administrator, in 
8    consultation with the utilities, the Commission, and other 
9    interested parties and subject to Commission oversight, 
10    shall develop and provide standard contract forms for the 
11    supplier contracts that meet generally accepted industry 
12    practices. Standard credit terms and instruments that meet 
13    generally accepted industry practices shall be similarly 
14    developed. The procurement administrator shall make 
15    available to the Commission all written comments it 
16    receives on the contract forms, credit terms, or 
17    instruments. If the procurement administrator cannot reach 
18    agreement with the applicable electric utility as to the 
19    contract terms and conditions, the procurement 
20    administrator must notify the Commission of any disputed 
21    terms and the Commission shall resolve the dispute. The 
22    terms of the contracts shall not be subject to negotiation 
23    by winning bidders, and the bidders must agree to the 
24    terms of the contract in advance so that winning bids are 
25    selected solely on the basis of price.
26        (3) Establishment of a market-based price benchmark. 
 
 
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1    As part of the development of the procurement process, the 
2    procurement administrator, in consultation with the 
3    Commission staff, Agency staff, and the procurement 
4    monitor, shall establish benchmarks for evaluating the 
5    final prices in the contracts for each of the products 
6    that will be procured through the procurement process. The 
7    benchmarks shall be based on price data for similar 
8    products for the same delivery period and same delivery 
9    hub, or other delivery hubs after adjusting for that 
10    difference. The price benchmarks may also be adjusted to 
11    take into account differences between the information 
12    reflected in the underlying data sources and the specific 
13    products and procurement process being used to procure 
14    power for the Illinois utilities. The benchmarks shall be 
15    confidential but shall be provided to, and will be subject 
16    to Commission review and approval, prior to a procurement 
17    event.
18        (4) Request for proposals competitive procurement 
19    process. The procurement administrator shall design and 
20    issue a request for proposals to supply electricity in 
21    accordance with each utility's procurement plan, as 
22    approved by the Commission. The request for proposals 
23    shall set forth a procedure for sealed, binding commitment 
24    bidding with pay-as-bid settlement, and provision for 
25    selection of bids on the basis of price.
26        (5) A plan for implementing contingencies in the event 
 
 
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1    of supplier default or failure of the procurement process 
2    to fully meet the expected load requirement due to 
3    insufficient supplier participation, Commission rejection 
4    of results, or any other cause.
5            (i) Event of supplier default: In the event of 
6        supplier default, the utility shall review the 
7        contract of the defaulting supplier to determine if 
8        the amount of supply is 200 megawatts or greater, and 
9        if there are more than 60 days remaining of the 
10        contract term. If both of these conditions are met, 
11        and the default results in termination of the 
12        contract, the utility shall immediately notify the 
13        Illinois Power Agency that a request for proposals 
14        must be issued to procure replacement power, and the 
15        procurement administrator shall run an additional 
16        procurement event. If the contracted supply of the 
17        defaulting supplier is less than 200 megawatts or 
18        there are less than 60 days remaining of the contract 
19        term, the utility shall procure power and energy from 
20        the applicable regional transmission organization 
21        market, including ancillary services, capacity, and 
22        day-ahead or real time energy, or both, for the 
23        duration of the contract term to replace the 
24        contracted supply; provided, however, that if a needed 
25        product is not available through the regional 
26        transmission organization market it shall be purchased 
 
 
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1        from the wholesale market.
2            (ii) Failure of the procurement process to fully 
3        meet the expected load requirement: If the procurement 
4        process fails to fully meet the expected load 
5        requirement due to insufficient supplier participation 
6        or due to a Commission rejection of the procurement 
7        results, the procurement administrator, the 
8        procurement monitor, and the Commission staff shall 
9        meet within 10 days to analyze potential causes of low 
10        supplier interest or causes for the Commission 
11        decision. If changes are identified that would likely 
12        result in increased supplier participation, or that 
13        would address concerns causing the Commission to 
14        reject the results of the prior procurement event, the 
15        procurement administrator may implement those changes 
16        and rerun the request for proposals process according 
17        to a schedule determined by those parties and 
18        consistent with Section 1-75 of the Illinois Power 
19        Agency Act and this subsection. In any event, a new 
20        request for proposals process shall be implemented by 
21        the procurement administrator within 90 days after the 
22        determination that the procurement process has failed 
23        to fully meet the expected load requirement.
24            (iii) In all cases where there is insufficient 
25        supply provided under contracts awarded through the 
26        procurement process to fully meet the electric 
 
 
10400SB0025ham004- 822 -LRB104 16098 AAS 29398 a

1        utility's load requirement, the utility shall meet the 
2        load requirement by procuring power and energy from 
3        the applicable regional transmission organization 
4        market, including ancillary services, capacity, and 
5        day-ahead or real time energy, or both; provided, 
6        however, that if a needed product is not available 
7        through the regional transmission organization market 
8        it shall be purchased from the wholesale market.
9        (6) The procurement processes described in this 
10    subsection and in subsection (c-5) of Section 1-75 of the 
11    Illinois Power Agency Act are exempt from the requirements 
12    of the Illinois Procurement Code, pursuant to Section 
13    20-10 of that Code.
14    (f) Within 2 business days after opening the sealed bids, 
15the procurement administrator shall submit a confidential 
16report to the Commission. The report shall contain the results 
17of the bidding for each of the products along with the 
18procurement administrator's recommendation for the acceptance 
19and rejection of bids based on the price benchmark criteria 
20and other factors observed in the process. The procurement 
21monitor also shall submit a confidential report to the 
22Commission within 2 business days after opening the sealed 
23bids. The report shall contain the procurement monitor's 
24assessment of bidder behavior in the process as well as an 
25assessment of the procurement administrator's compliance with 
26the procurement process and rules. The Commission shall review 
 
 
10400SB0025ham004- 823 -LRB104 16098 AAS 29398 a

1the confidential reports submitted by the procurement 
2administrator and procurement monitor, and shall accept or 
3reject the recommendations of the procurement administrator 
4within 2 business days after receipt of the reports.
5    (g) Within 3 business days after the Commission decision 
6approving the results of a procurement event, the utility 
7shall enter into binding contractual arrangements with the 
8winning suppliers using the standard form contracts; except 
9that the utility shall not be required either directly or 
10indirectly to execute the contracts if a tariff that is 
11consistent with subsection (l) of this Section has not been 
12approved and placed into effect for that utility.
13    (h) For the procurement of standard wholesale products, 
14the names of the successful bidders and the load weighted 
15average of the winning bid prices for each contract type and 
16for each contract term shall be made available to the public at 
17the time of Commission approval of a procurement event. For 
18procurements conducted to meet the requirements of subsection 
19(b) of Section 1-56 or subsection (c) of Section 1-75 of the 
20Illinois Power Agency Act governed by the provisions of this 
21Section, the address and nameplate capacity of the new 
22renewable energy generating facility proposed by a winning 
23bidder shall also be made available to the public at the time 
24of Commission approval of a procurement event, along with the 
25business address and contact information for any winning 
26bidder. An estimate or approximation of the nameplate capacity 
 
 
10400SB0025ham004- 824 -LRB104 16098 AAS 29398 a

1of the new renewable energy generating facility may be 
2disclosed if necessary to protect the confidentiality of 
3individual bid prices.
4    The Commission, the procurement monitor, the procurement 
5administrator, the Illinois Power Agency, and all participants 
6in the procurement process shall maintain the confidentiality 
7of all other supplier and bidding information in a manner 
8consistent with all applicable laws, rules, regulations, and 
9tariffs. Confidential information, including the confidential 
10reports submitted by the procurement administrator and 
11procurement monitor pursuant to subsection (f) of this 
12Section, shall not be made publicly available and shall not be 
13discoverable by any party in any proceeding, absent a 
14compelling demonstration of need, nor shall those reports be 
15admissible in any proceeding other than one for law 
16enforcement purposes.
17    For procurements conducted to meet the requirements of 
18subsection (b) of Section 1-56 or subsection (c) of Section 
191-75 of the Illinois Power Agency Act, the Illinois Power 
20Agency may release aggregated information related to 
21participation levels across product types and the basis of 
22rejection for non-accepted bids if the Commission, the 
23procurement monitor, the procurement administrator, and the 
24Illinois Power Agency determine that the release of this 
25information would not result in the disclosure of confidential 
26bid information or negatively impact the competitiveness of 
 
 
10400SB0025ham004- 825 -LRB104 16098 AAS 29398 a

1future renewable energy credit procurements. The Agency may 
2also release information about the development status of new 
3renewable energy projects under contract and project-specific 
4information about renewable energy credit delivery quantities 
5for projects under contract if the Commission, the procurement 
6monitor, the procurement administrator, and the Illinois Power 
7Agency determine that the release of this information would 
8not result in the disclosure of confidential bid information 
9or negatively impact the competitiveness of future renewable 
10energy credit procurements.    
11    (i) Within 2 business days after a Commission decision 
12approving the results of a procurement event or such other 
13date as may be required by the Commission from time to time, 
14the utility shall file for informational purposes with the 
15Commission its actual or estimated retail supply charges, as 
16applicable, by customer supply group reflecting the costs 
17associated with the procurement and computed in accordance 
18with the tariffs filed pursuant to subsection (l) of this 
19Section and approved by the Commission.
20    (j) Within 60 days following August 28, 2007 (the 
21effective date of Public Act 95-481), each electric utility 
22that on December 31, 2005 provided electric service to at 
23least 100,000 customers in Illinois shall prepare and file 
24with the Commission an initial procurement plan, which shall 
25conform in all material respects to the requirements of the 
26procurement plan set forth in subsection (b); provided, 
 
 
10400SB0025ham004- 826 -LRB104 16098 AAS 29398 a

1however, that the Illinois Power Agency Act shall not apply to 
2the initial procurement plan prepared pursuant to this 
3subsection. The initial procurement plan shall identify the 
4portfolio of power and energy products to be procured and 
5delivered for the period June 2008 through May 2009, and shall 
6identify the proposed procurement administrator, who shall 
7have the same experience and expertise as is required of a 
8procurement administrator hired pursuant to Section 1-75 of 
9the Illinois Power Agency Act. Copies of the procurement plan 
10shall be posted and made publicly available on the 
11Commission's website. The initial procurement plan may include 
12contracts for renewable resources that extend beyond May 2009.
13        (i) Within 14 days following filing of the initial 
14    procurement plan, any person may file a detailed objection 
15    with the Commission contesting the procurement plan 
16    submitted by the electric utility. All objections to the 
17    electric utility's plan shall be specific, supported by 
18    data or other detailed analyses. The electric utility may 
19    file a response to any objections to its procurement plan 
20    within 7 days after the date objections are due to be 
21    filed. Within 7 days after the date the utility's response 
22    is due, the Commission shall determine whether a hearing 
23    is necessary. If it determines that a hearing is 
24    necessary, it shall require the hearing to be completed 
25    and issue an order on the procurement plan within 60 days 
26    after the filing of the procurement plan by the electric 
 
 
10400SB0025ham004- 827 -LRB104 16098 AAS 29398 a

1    utility.
2        (ii) The order shall approve or modify the procurement 
3    plan, approve an independent procurement administrator, 
4    and approve or modify the electric utility's tariffs that 
5    are proposed with the initial procurement plan. The 
6    Commission shall approve the procurement plan if the 
7    Commission determines that it will ensure adequate, 
8    reliable, affordable, efficient, and environmentally 
9    sustainable electric service at the lowest total cost over 
10    time, taking into account any benefits of price stability.
11    (k) (Blank).
12    (k-5) (Blank).
13    (l) An electric utility shall recover its costs incurred 
14under this Section and subsection (c-5) of Section 1-75 of the 
15Illinois Power Agency Act, including, but not limited to, the 
16costs of procuring power and energy demand-response resources 
17under this Section and its costs for purchasing renewable 
18energy credits pursuant to subsection (c-5) of Section 1-75 of 
19the Illinois Power Agency Act. The utility shall file with the 
20initial procurement plan its proposed tariffs through which 
21its costs of procuring power that are incurred pursuant to a 
22Commission-approved procurement plan and those other costs 
23identified in this subsection (l), will be recovered. The 
24tariffs shall include a formula rate or charge designed to 
25pass through both the costs incurred by the utility in 
26procuring a supply of electric power and energy for the 
 
 
10400SB0025ham004- 828 -LRB104 16098 AAS 29398 a

1applicable customer classes with no mark-up or return on the 
2price paid by the utility for that supply, plus any just and 
3reasonable costs that the utility incurs in arranging and 
4providing for the supply of electric power and energy. The 
5formula rate or charge shall also contain provisions that 
6ensure that its application does not result in over or under 
7recovery due to changes in customer usage and demand patterns, 
8and that provide for the correction, on at least an annual 
9basis, of any accounting errors that may occur. A utility 
10shall recover through the tariff all reasonable costs incurred 
11to implement or comply with any procurement plan that is 
12developed and put into effect pursuant to Section 1-75 of the 
13Illinois Power Agency Act and this Section, and for the 
14procurement of renewable energy credits pursuant to subsection 
15(c-5) of Section 1-75 of the Illinois Power Agency Act, 
16including any fees assessed by the Illinois Power Agency, 
17costs associated with load balancing, and contingency plan 
18costs. The electric utility shall also recover its full costs 
19of procuring electric supply for which it contracted before 
20the effective date of this Section in conjunction with the 
21provision of full requirements service under fixed-price 
22bundled service tariffs subsequent to December 31, 2006. All 
23such costs shall be deemed to have been prudently incurred. 
24The pass-through tariffs that are filed and approved pursuant 
25to this Section shall not be subject to review under, or in any 
26way limited by, Section 16-111(i) of this Act. All of the costs 
 
 
10400SB0025ham004- 829 -LRB104 16098 AAS 29398 a

1incurred by the electric utility associated with the purchase 
2of zero emission credits in accordance with subsection (d-5) 
3of Section 1-75 of the Illinois Power Agency Act, all costs 
4incurred by the electric utility associated with the purchase 
5of carbon mitigation credits in accordance with subsection 
6(d-10) of Section 1-75 of the Illinois Power Agency Act, and, 
7beginning June 1, 2017, all of the costs incurred by the 
8electric utility associated with the purchase of renewable 
9energy resources in accordance with Sections 1-56 and 1-75 of 
10the Illinois Power Agency Act, and all of the costs incurred by 
11the electric utility in purchasing renewable energy credits in 
12accordance with subsection (c-5) of Section 1-75 of the 
13Illinois Power Agency Act, shall be recovered through the 
14electric utility's tariffed charges applicable to all of its 
15retail customers, as specified in subsection (k) or subsection 
16(i-5), as applicable, of Section 16-108 of this Act, and shall 
17not be recovered through the electric utility's tariffed 
18charges for electric power and energy supply to its eligible 
19retail customers.
20    (m) The Commission has the authority to adopt rules to 
21carry out the provisions of this Section. For the public 
22interest, safety, and welfare, the Commission also has 
23authority to adopt rules to carry out the provisions of this 
24Section on an emergency basis immediately following August 28, 
252007 (the effective date of Public Act 95-481).
26    (n) Notwithstanding any other provision of this Act, any 
 
 
10400SB0025ham004- 830 -LRB104 16098 AAS 29398 a

1affiliated electric utilities that submit a single procurement 
2plan covering their combined needs may procure for those 
3combined needs in conjunction with that plan, and may enter 
4jointly into power supply contracts, purchases, and other 
5procurement arrangements, and allocate capacity and energy and 
6cost responsibility therefor among themselves in proportion to 
7their requirements.
8    (o) On or before June 1 of each year, the Commission shall 
9hold an informal hearing for the purpose of receiving comments 
10on the prior year's procurement process and any 
11recommendations for change. 
12    (p) An electric utility subject to this Section may 
13propose to invest, lease, own, or operate an electric 
14generation facility as part of its procurement plan, provided 
15the utility demonstrates that such facility is the least-cost 
16option to provide electric service to those retail customers 
17included in the plan's electric supply service requirements. 
18If the facility is shown to be the least-cost option and is 
19included in a procurement plan prepared in accordance with 
20Section 1-75 of the Illinois Power Agency Act and this 
21Section, then the electric utility shall make a filing 
22pursuant to Section 8-406 of this Act, and may request of the 
23Commission any statutory relief required thereunder. If the 
24Commission grants all of the necessary approvals for the 
25proposed facility, such supply shall thereafter be considered 
26as a pre-existing contract under subsection (b) of this 
 
 
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1Section. The Commission shall in any order approving a 
2proposal under this subsection specify how the utility will 
3recover the prudently incurred costs of investing in, leasing, 
4owning, or operating such generation facility through just and 
5reasonable rates charged to those retail customers included in 
6the plan's electric supply service requirements. Cost recovery 
7for facilities included in the utility's procurement plan 
8pursuant to this subsection shall not be subject to review 
9under or in any way limited by the provisions of Section 
1016-111(i) of this Act. Nothing in this Section is intended to 
11prohibit a utility from filing for a fuel adjustment clause as 
12is otherwise permitted under Section 9-220 of this Act. 
13    (q) If the Illinois Power Agency filed with the 
14Commission, under Section 16-111.5 of this Act, its proposed 
15procurement plan for the period commencing June 1, 2017, and 
16the Commission has not yet entered its final order approving 
17the plan on or before the effective date of this amendatory Act 
18of the 99th General Assembly, then the Illinois Power Agency 
19shall file a notice of withdrawal with the Commission, after 
20the effective date of this amendatory Act of the 99th General 
21Assembly, to withdraw the proposed procurement of renewable 
22energy resources to be approved under the plan, other than the 
23procurement of renewable energy credits from distributed 
24renewable energy generation devices using funds previously 
25collected from electric utilities' retail customers that take 
26service pursuant to electric utilities' hourly pricing tariff 
 
 
10400SB0025ham004- 832 -LRB104 16098 AAS 29398 a

1or tariffs and, for an electric utility that serves less than 
2100,000 retail customers in the State, other than the 
3procurement of renewable energy credits from distributed 
4renewable energy generation devices. Upon receipt of the 
5notice, the Commission shall enter an order that approves the 
6withdrawal of the proposed procurement of renewable energy 
7resources from the plan. The initially proposed procurement of 
8renewable energy resources shall not be approved or be the 
9subject of any further hearing, investigation, proceeding, or 
10order of any kind.
11    This amendatory Act of the 99th General Assembly preempts 
12and supersedes any order entered by the Commission that 
13approved the Illinois Power Agency's procurement plan for the 
14period commencing June 1, 2017, to the extent it is 
15inconsistent with the provisions of this amendatory Act of the 
1699th General Assembly. To the extent any previously entered 
17order approved the procurement of renewable energy resources, 
18the portion of that order approving the procurement shall be 
19void, other than the procurement of renewable energy credits 
20from distributed renewable energy generation devices using 
21funds previously collected from electric utilities' retail 
22customers that take service under electric utilities' hourly 
23pricing tariff or tariffs and, for an electric utility that 
24serves less than 100,000 retail customers in the State, other 
25than the procurement of renewable energy credits for 
26distributed renewable energy generation devices. 
 
 
10400SB0025ham004- 833 -LRB104 16098 AAS 29398 a

1(Source: P.A. 102-662, eff. 9-15-21.)
 
2    (220 ILCS 5/16-111.7)
3    Sec. 16-111.7. On-bill financing program; electric 
4utilities.
5    (a) The Illinois General Assembly finds that Illinois 
6homes and businesses have the potential to save energy through 
7conservation and cost-effective energy efficiency measures. 
8Programs created pursuant to this Section will allow utility 
9customers to purchase cost-effective energy efficiency 
10measures, including measures set forth in a 
11Commission-approved energy efficiency and demand-response plan 
12under Section 8-103 or 8-103B of this Act, with no required 
13initial upfront payment, and to pay the cost of those products 
14and services over time on their utility bill.
15    (b) Notwithstanding any other provision of this Act, an 
16electric utility serving more than 100,000 customers on 
17January 1, 2009 shall offer a Commission-approved on-bill 
18financing program ("program") that allows its eligible retail 
19customers, as that term is defined in Section 16-111.5 of this 
20Act, who own a residential single family home, duplex, or 
21other residential building with 4 or less units, or 
22condominium at which the electric service is being provided 
23(i) to borrow funds from a third party lender in order to 
24purchase electric energy efficiency measures approved under 
25the program for installation in such home or condominium 
 
 
10400SB0025ham004- 834 -LRB104 16098 AAS 29398 a

1without any required upfront payment and (ii) to pay back such 
2funds over time through the electric utility's bill. Based 
3upon the process described in subsection (b-5) of this 
4Section, small commercial customers who own the premises at 
5which electric service is being provided may be included in 
6such program. After receiving a request from an electric 
7utility for approval of a proposed program and tariffs 
8pursuant to this Section, the Commission shall render its 
9decision within 120 days. If no decision is rendered within 
10120 days, then the request shall be deemed to be approved.
11    Beginning no later than December 31, 2013, an electric 
12utility subject to this subsection (b) shall also offer its 
13program to eligible retail customers that own multifamily 
14residential or mixed-use buildings with no more than 50 
15residential units, provided, however, that such customers must 
16either be a residential customer or small commercial customer 
17and may not use the program in such a way that repayment of the 
18cost of energy efficiency measures is made through tenants' 
19utility bills. An electric utility may impose a per site loan 
20limit not to exceed $150,000. The program, and loans issued 
21thereunder, shall only be offered to customers of the utility 
22that meet the requirements of this Section and that also have 
23an electric service account at the premises where the energy 
24efficiency measures being financed shall be installed. 
25Beginning no later than 2 years after the effective date of 
26this amendatory Act of the 99th General Assembly, the 50 
 
 
10400SB0025ham004- 835 -LRB104 16098 AAS 29398 a

1residential unit limitation described in this paragraph shall 
2no longer apply, and the utility shall replace the per site 
3loan limit of $150,000 with a loan limit that correlates to a 
4maximum monthly payment that does not exceed 50% of the 
5customer's average utility bill over the prior 12-month 
6period.
7    Beginning no later than 2 years after the effective date 
8of this amendatory Act of the 99th General Assembly, an 
9electric utility subject to this subsection (b) shall also 
10offer its program to eligible retail customers that are Unit 
11Owners' Associations, as defined in subsection (o) of Section 
122 of the Condominium Property Act, or Master Associations, as 
13defined in subsection (u) of the Condominium Property Act. 
14However, such customers must either be residential customers 
15or small commercial customers and may not use the program in 
16such a way that repayment of the cost of energy efficiency 
17measures is made through unit owners' utility bills. The 
18program and loans issued under the program shall only be 
19offered to customers of the utility that meet the requirements 
20of this Section and that also have an electric service account 
21at the premises where the energy efficiency measures being 
22financed shall be installed. 
23    For purposes of this Section, "small commercial customer" 
24means, for an electric utility serving more than 3,000,000 
25retail customers, those customers having peak demand of less 
26than 100 kilowatts, and, for an electric utility serving less 
 
 
10400SB0025ham004- 836 -LRB104 16098 AAS 29398 a

1than 3,000,000 retail customers, those customers having peak 
2demand of less than 150 kilowatts; provided, however, that in 
3the event the Commission, after the effective date of this 
4amendatory Act of the 98th General Assembly, approves changes 
5to a utility's tariffs that reflects new or revised demand 
6criteria for the utility's customer rate classifications, then 
7the utility may file a petition with the Commission to revise 
8the applicable definition of a small commercial customer to 
9reflect the new or revised demand criteria for the purposes of 
10this Section. After notice and hearing, the Commission shall 
11enter an order approving, or approving with modification, the 
12revised definition within 60 days after the utility files the 
13petition. 
14    (b-5) Within 30 days after the effective date of this 
15amendatory Act of the 96th General Assembly, the Commission 
16shall convene a workshop process during which interested 
17participants may discuss issues related to the program, 
18including program design, eligible electric energy efficiency 
19measures, vendor qualifications, and a methodology for 
20ensuring ongoing compliance with such qualifications, 
21financing, sample documents such as request for proposals, 
22contracts and agreements, dispute resolution, pre-installment 
23and post-installment verification, and evaluation. The 
24workshop process shall be completed within 150 days after the 
25effective date of this amendatory Act of the 96th General 
26Assembly.
 
 
10400SB0025ham004- 837 -LRB104 16098 AAS 29398 a

1    (c) Not later than 60 days following completion of the 
2workshop process described in subsection (b-5) of this 
3Section, each electric utility subject to subsection (b) of 
4this Section shall submit a proposed program to the Commission 
5that contains the following components:
6        (1) A list of recommended electric energy efficiency 
7    measures that will be eligible for on-bill financing. An 
8    eligible electric energy efficiency measure ("measure") 
9    shall be a product or service for which one or more of the 
10    following is true:
11            (A) (blank); 
12            (B) the projected electricity savings (determined 
13        by rates in effect at the time of purchase) are 
14        sufficient to cover the costs of implementing the 
15        measures, including finance charges and any program 
16        fees not recovered pursuant to subsection (f) of this 
17        Section; or
18            (C) the product or service is included in a 
19        Commission-approved energy efficiency and 
20        demand-response plan under Section 8-103 or 8-103B of 
21        this Act. 
22        (1.5) Beginning no later than 2 years after the 
23    effective date of this amendatory Act of the 99th General 
24    Assembly, an eligible electric energy efficiency measure 
25    (measure) shall be a product or service that qualifies 
26    under subparagraph (B) or (C) of paragraph (1) of this 
 
 
10400SB0025ham004- 838 -LRB104 16098 AAS 29398 a

1    subsection (c) or for which one or more of the following is 
2    true:
3            (A) a building energy assessment, performed by an 
4        energy auditor who is certified by the Building 
5        Performance Institute or who holds a similar 
6        certification, has recommended the product or service 
7        as likely to be cost effective over the course of its 
8        installed life for the building in which the measure 
9        is to be installed; or
10            (B) the product or service is necessary to safely 
11        or correctly install to code or industry standard an 
12        efficiency measure, including, but not limited to, 
13        installation work; changes needed to plumbing or 
14        electrical connections; upgrades to wiring or 
15        fixtures; removal of hazardous materials; correction 
16        of leaks; changes to thermostats, controls, or similar 
17        devices; and changes to venting or exhaust 
18        necessitated by the measure. However, the costs of the 
19        product or service described in this subparagraph (B) 
20        shall not exceed 25% of the total cost of installing 
21        the measure. 
22        (2) The electric utility shall issue a request for 
23    proposals ("RFP") to lenders for purposes of providing 
24    financing to participants to pay for approved measures. 
25    The RFP criteria shall include, but not be limited to, the 
26    interest rate, origination fees, and credit terms. The 
 
 
10400SB0025ham004- 839 -LRB104 16098 AAS 29398 a

1    utility shall select the winning bidders based on its 
2    evaluation of these criteria, with a preference for those 
3    bids containing the rates, fees, and terms most favorable 
4    to participants;
5        (3) The utility shall work with the lenders selected 
6    pursuant to the RFP process, and with vendors, to 
7    establish the terms and processes pursuant to which a 
8    participant can purchase eligible electric energy 
9    efficiency measures using the financing obtained from the 
10    lender. The vendor shall explain and offer the approved 
11    financing packaging to those customers identified in 
12    subsection (b) of this Section and shall assist customers 
13    in applying for financing. As part of the process, vendors 
14    shall also provide to participants information about any 
15    other incentives that may be available for the measures.
16        (4) The lender shall conduct credit checks or 
17    undertake other appropriate measures to limit credit risk, 
18    and shall review and approve or deny financing 
19    applications submitted by customers identified in 
20    subsection (b) of this Section. Following the lender's 
21    approval of financing and the participant's purchase of 
22    the measure or measures, the lender shall forward payment 
23    information to the electric utility, and the utility shall 
24    add as a separate line item on the participant's utility 
25    bill a charge showing the amount due under the program 
26    each month.
 
 
10400SB0025ham004- 840 -LRB104 16098 AAS 29398 a

1        (5) A loan issued to a participant pursuant to the 
2    program shall be the sole responsibility of the 
3    participant, and any dispute that may arise concerning the 
4    loan's terms, conditions, or charges shall be resolved 
5    between the participant and lender. Upon transfer of the 
6    property title for the premises at which the participant 
7    receives electric service from the utility or the 
8    participant's request to terminate service at such 
9    premises, the participant shall pay in full its electric 
10    utility bill, including all amounts due under the program, 
11    provided that this obligation may be modified as provided 
12    in subsection (g) of this Section. Amounts due under the 
13    program shall be deemed amounts owed for residential and, 
14    as appropriate, small commercial electric service.
15        (6) The electric utility shall remit payment in full 
16    to the lender each month on behalf of the participant. In 
17    the event a participant defaults on payment of its 
18    electric utility bill, the electric utility shall continue 
19    to remit all payments due under the program to the lender, 
20    and the utility shall be entitled to recover all costs 
21    related to a participant's nonpayment through the 
22    automatic adjustment clause tariff established pursuant to 
23    Section 16-111.8 of this Act. In addition, the electric 
24    utility shall retain a security interest in the measure or 
25    measures purchased under the program, and the utility 
26    retains its right to disconnect a participant that 
 
 
10400SB0025ham004- 841 -LRB104 16098 AAS 29398 a

1    defaults on the payment of its utility bill.
2        (7) The total outstanding amount financed under the 
3    program in this subsection and subsection (c-5) of this 
4    Section shall not exceed $2.5 million for an electric 
5    utility or electric utilities under a single holding 
6    company, provided that the electric utility or electric 
7    utilities may petition the Commission for an increase in 
8    such amount. Beginning after the effective date of this 
9    amendatory Act of the 99th General Assembly, the total 
10    maximum outstanding amount financed under the program in 
11    this subsection and subsections (c-5) and (c-10) of this 
12    Section shall increase by $5,000,000 per year until such 
13    time as the total maximum outstanding amount financed 
14    reaches $20,000,000. For purposes of this Section, 
15    "maximum outstanding amount financed" means the sum of all 
16    principal that has been loaned and not yet repaid. 
17    (c-5) Within 120 days after the effective date of this 
18amendatory Act of the 98th General Assembly, each electric 
19utility subject to the requirements of this Section shall 
20submit an informational filing to the Commission that 
21describes its plan for implementing the provisions of this 
22amendatory Act of the 98th General Assembly on or before 
23December 31, 2013. Such filing shall also describe how the 
24electric utility shall coordinate its program with any gas 
25utility or utilities that provide gas service to buildings 
26within the electric utility's service territory so that it is 
 
 
10400SB0025ham004- 842 -LRB104 16098 AAS 29398 a

1practical and feasible for the owner of a multifamily building 
2to make a single application to access loans for both gas and 
3electric energy efficiency measures in any individual 
4building.
5    (c-10) No later than 365 days after the effective date of 
6this amendatory Act of the 99th General Assembly, each 
7electric utility subject to the requirements of this Section 
8shall submit an informational filing to the Commission that 
9describes its plan for implementing the provisions of this 
10amendatory Act of the 99th General Assembly that were 
11incorporated into this Section. Such filing shall also include 
12the criteria to be used by the program for determining if 
13measures to be financed are eligible electric energy 
14efficiency measures, as defined by paragraph (1.5) of 
15subsection (c) of this Section. 
16    (d) A program approved by the Commission shall also 
17include the following criteria and guidelines for such 
18program:
19        (1) guidelines for financing of measures installed 
20    under a program, including, but not limited to, RFP 
21    criteria and limits on both individual loan amounts and 
22    the duration of the loans;
23        (2) criteria and standards for identifying and 
24    approving measures;
25        (3) qualifications of vendors that will market or 
26    install measures, as well as a methodology for ensuring 
 
 
10400SB0025ham004- 843 -LRB104 16098 AAS 29398 a

1    ongoing compliance with such qualifications;
2        (4) sample contracts and agreements necessary to 
3    implement the measures and program; and
4        (5) the types of data and information that utilities 
5    and vendors participating in the program shall collect for 
6    purposes of preparing the reports required under 
7    subsection (g) of this Section.
8    (e) The proposed program submitted by each electric 
9utility shall be consistent with the provisions of this 
10Section that define operational, financial and billing 
11arrangements between and among program participants, vendors, 
12lenders, and the electric utility.
13    (f) An electric utility shall recover all of the prudently 
14incurred costs of offering a program approved by the 
15Commission pursuant to this Section, including, but not 
16limited to, all start-up and administrative costs and the 
17costs for program evaluation. All prudently incurred costs 
18under this Section shall be recovered from the residential and 
19small commercial retail customer classes eligible to 
20participate in the program through the automatic adjustment 
21clause tariff established pursuant to Section 8-103 or 8-103B 
22of this Act.
23    (g) An independent evaluation of a program shall be 
24conducted after 3 years of the program's operation. The 
25electric utility shall retain an independent evaluator who 
26shall evaluate the effects of the measures installed under the 
 
 
10400SB0025ham004- 844 -LRB104 16098 AAS 29398 a

1program and the overall operation of the program, including, 
2but not limited to, customer eligibility criteria and whether 
3the payment obligation for permanent electric energy 
4efficiency measures that will continue to provide benefits of 
5energy savings should attach to the meter location. As part of 
6the evaluation process, the evaluator shall also solicit 
7feedback from participants and interested stakeholders. The 
8evaluator shall issue a report to the Commission on its 
9findings no later than 4 years after the date on which the 
10program commenced, and the Commission shall issue a report to 
11the Governor and General Assembly including a summary of the 
12information described in this Section as well as its 
13recommendations as to whether the program should be 
14discontinued, continued with modification or modifications or 
15continued without modification, provided that any recommended 
16modifications shall only apply prospectively and to measures 
17not yet installed or financed.
18    (h) An electric utility offering a Commission-approved 
19program pursuant to this Section shall not be required to 
20comply with any other statute, order, rule, or regulation of 
21this State that may relate to the offering of such program, 
22provided that nothing in this Section is intended to limit the 
23electric utility's obligation to comply with this Act and the 
24Commission's orders, rules, and regulations, including Part 
25280 of Title 83 of the Illinois Administrative Code.
26    (i) The source of a utility customer's electric supply 
 
 
10400SB0025ham004- 845 -LRB104 16098 AAS 29398 a

1shall not disqualify a customer from participation in the 
2utility's on-bill financing program. Customers of alternative 
3retail electric suppliers may participate in the program under 
4the same terms and conditions applicable to the utility's 
5supply customers.
6    (j) This Section is repealed on January 1, 2027.    
7(Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17.)
 
8    (220 ILCS 5/16-115A)
9    Sec. 16-115A. Obligations of alternative retail electric 
10suppliers.
11    (a) An alternative retail electric supplier:
12        (i) shall comply with the requirements imposed on 
13    public utilities by Sections 8-201 through 8-207, 8-301, 
14    8-505 and 8-507 of this Act, to the extent that these 
15    Sections have application to the services being offered by 
16    the alternative retail electric supplier;
17        (ii) shall continue to comply with the requirements 
18    for certification stated in subsection (d) of Section 
19    16-115;
20        (iii) by May 31, 2020 and every June 30 thereafter, 
21    shall submit to the Commission and the Office of the 
22    Attorney General the rates the retail electric supplier 
23    charged to residential customers in the prior year, 
24    including each distinct rate charged and whether the rate 
25    was a fixed or variable rate, the basis for the variable 
 
 
10400SB0025ham004- 846 -LRB104 16098 AAS 29398 a

1    rate, and any fees charged in addition to the supply rate, 
2    including monthly fees, flat fees, or other service 
3    charges; and
4        (iv) shall make publicly available on its website, 
5    without the need for a customer login, rate information 
6    for all of its variable, time-of-use, and fixed rate 
7    contracts currently available to residential customers, 
8    including, but not limited to, fixed monthly charges, 
9    early termination fees, and kilowatt-hour charges; .
10        (v) shall provide to the Commission, in the form and 
11    manner requested, the information necessary for the 
12    Commission to compile and submit the integrated resource 
13    plan required under Section 16-201; and
14        (vi) shall comply with the Commission's determinations 
15    made pursuant to subsection (b-10) of Section 16-111.5, 
16    including, but not limited to, the imposition of any 
17    collections, the execution of any contracts, and the 
18    required performance under any contracts developed 
19    thereunder.
20    (b) An alternative retail electric supplier shall obtain 
21verifiable authorization from a customer, in a form or manner 
22approved by the Commission consistent with Section 2EE of the 
23Consumer Fraud and Deceptive Business Practices Act, before 
24the customer is switched from another supplier.
25    (c) No alternative retail electric supplier, or electric 
26utility other than the electric utility in whose service area 
 
 
10400SB0025ham004- 847 -LRB104 16098 AAS 29398 a

1a customer is located, shall (i) enter into or employ any 
2arrangements which have the effect of preventing a retail 
3customer with a maximum electrical demand of less than one 
4megawatt from having access to the services of the electric 
5utility in whose service area the customer is located or (ii) 
6charge retail customers for such access. This subsection shall 
7not be construed to prevent an arms-length agreement between a 
8supplier and a retail customer that sets a term of service, 
9notice period for terminating service and provisions governing 
10early termination through a tariff or contract as allowed by 
11Section 16-119.
12    (d) An alternative retail electric supplier that is 
13certified to serve residential or small commercial retail 
14customers shall not:
15        (1) deny service to a customer or group of customers 
16    nor establish any differences as to prices, terms, 
17    conditions, services, products, facilities, or in any 
18    other respect, whereby such denial or differences are 
19    based upon race, gender or income, except as provided in 
20    Section 16-115E.
21        (2) deny service to a customer or group of customers 
22    based on locality nor establish any unreasonable 
23    difference as to prices, terms, conditions, services, 
24    products, or facilities as between localities.
25        (3) warrant that it has a residential customer or 
26    small commercial retail customer's express consent 
 
 
10400SB0025ham004- 848 -LRB104 16098 AAS 29398 a

1    agreement to access interval data as described in 
2    subsection (b) of Section 16-122, unless the alternative 
3    retail electric supplier has:
4            (A) disclosed to the consumer at the outset of the 
5        offer that the alternative retail electric supplier 
6        will access the consumer's interval data from the 
7        consumer's utility with the consumer's express 
8        agreement and the consumer's option to refuse to 
9        provide express agreement to access the consumer's 
10        interval data; and
11            (B) obtained the consumer's express agreement for 
12        the alternative retail electric supplier to access the 
13        consumer's interval data from the consumer's utility 
14        in a separate letter of agency, a distinct response to 
15        a third-party verification, or as a separate 
16        affirmative consent during a recorded enrollment 
17        initiated by the consumer. The disclosure by the 
18        alternative retail electric supplier to the consumer 
19        in this Section shall be conducted in, translated 
20        into, and provided in a language in which the consumer 
21        subject to the disclosure is able to understand and 
22        communicate.
23        (4) release, sell, license, or otherwise disclose any 
24    customer interval data obtained under Section 16-122 to 
25    any third person except as provided for in Section 16-122 
26    and paragraphs (1) through (4) of subsection (d-5) of 
 
 
10400SB0025ham004- 849 -LRB104 16098 AAS 29398 a

1    Section 2EE of the Consumer Fraud and Deceptive Business 
2    Practices Act. 
3    (e) An alternative retail electric supplier shall comply 
4with the following requirements with respect to the marketing, 
5offering and provision of products or services to residential 
6and small commercial retail customers:
7        (i) All marketing materials, including, but not 
8    limited to, electronic marketing materials, in-person 
9    solicitations, and telephone solicitations, shall contain 
10    information that adequately discloses the prices, terms, 
11    and conditions of the products or services that the 
12    alternative retail electric supplier is offering or 
13    selling to the customer and shall disclose the current 
14    utility electric supply price to compare applicable at the 
15    time the alternative retail electric supplier is offering 
16    or selling the products or services to the customer and 
17    shall disclose the date on which the utility electric 
18    supply price to compare became effective and the date on 
19    which it will expire. The utility electric supply price to 
20    compare shall be the sum of the electric supply charge and 
21    the transmission services charge and shall not include the 
22    purchased electricity adjustment. The disclosure shall 
23    include a statement that the price to compare does not 
24    include the purchased electricity adjustment, and, if 
25    applicable, the range of the purchased electricity 
26    adjustment. All marketing materials, including, but not 
 
 
10400SB0025ham004- 850 -LRB104 16098 AAS 29398 a

1    limited to, electronic marketing materials, in-person 
2    solicitations, and telephone solicitations, shall include 
3    the following statement: 
4            "(Name of the alternative retail electric 
5        supplier) is not the same entity as your electric 
6        delivery company. You are not required to enroll with 
7        (name of alternative retail electric supplier). 
8        Beginning on (effective date), the electric supply 
9        price to compare is (price in cents per kilowatt 
10        hour). The electric utility electric supply price will 
11        expire on (expiration date). The utility electric 
12        supply price to compare does not include the purchased 
13        electricity adjustment factor. For more information go 
14        to the Illinois Commerce Commission's free website at 
15        www.pluginillinois.org.
16        If applicable, the statement shall also include the 
17    following statement:
18            "The purchased electricity adjustment factor may 
19        range between +.5 cents and -.5 cents per kilowatt 
20        hour.". 
21        This paragraph (i) does not apply to goodwill or 
22    institutional advertising. 
23        (ii) Before any customer is switched from another 
24    supplier, the alternative retail electric supplier shall 
25    give the customer written information that adequately 
26    discloses, in plain language, the prices, terms and 
 
 
10400SB0025ham004- 851 -LRB104 16098 AAS 29398 a

1    conditions of the products and services being offered and 
2    sold to the customer. This written information shall be 
3    provided in a language in which the customer subject to 
4    the marketing or solicitation is able to understand and 
5    communicate, and the alternative retail electric supplier 
6    shall not switch a customer who is unable to understand 
7    and communicate in a language in which the marketing or 
8    solicitation was conducted. The alternative retail 
9    electric supplier shall comply with Section 2N of the 
10    Consumer Fraud and Deceptive Business Practices Act. 
11        (iii) An alternative retail electric supplier shall 
12    provide documentation to the Commission and to customers 
13    that substantiates any claims made by the alternative 
14    retail electric supplier regarding the technologies and 
15    fuel types used to generate the electricity offered or 
16    sold to customers.
17        (iv) The alternative retail electric supplier shall 
18    provide to the customer (1) itemized billing statements 
19    that describe the products and services provided to the 
20    customer and their prices, and (2) an additional 
21    statement, at least annually, that adequately discloses 
22    the average monthly prices, and the terms and conditions, 
23    of the products and services sold to the customer.
24        (v) All in-person and telephone solicitations shall be 
25    conducted in, translated into, and provided in a language 
26    in which the consumer subject to the marketing or 
 
 
10400SB0025ham004- 852 -LRB104 16098 AAS 29398 a

1    solicitation is able to understand and communicate. An 
2    alternative retail electric supplier shall terminate a 
3    solicitation if the consumer subject to the marketing or 
4    communication is unable to understand and communicate in 
5    the language in which the marketing or solicitation is 
6    being conducted. An alternative retail electric supplier 
7    shall comply with Section 2N of the Consumer Fraud and 
8    Deceptive Business Practices Act.
9        (vi) Each alternative retail electric supplier shall 
10    conduct training for individual representatives engaged in 
11    in-person solicitation and telemarketing to residential 
12    customers on behalf of that alternative retail electric 
13    supplier prior to conducting any such solicitations on the 
14    alternative retail electric supplier's behalf. Each 
15    alternative retail electric supplier shall submit a copy 
16    of its training material to the Commission on an annual 
17    basis and the Commission shall have the right to review 
18    and require updates to the material. After initial 
19    training, each alternative retail electric supplier shall 
20    be required to conduct refresher training for its 
21    individual representatives every 6 months. 
22    (f) An alternative retail electric supplier may limit the 
23overall size or availability of a service offering by 
24specifying one or more of the following: a maximum number of 
25customers, maximum amount of electric load to be served, time 
26period during which the offering will be available, or other 
 
 
10400SB0025ham004- 853 -LRB104 16098 AAS 29398 a

1comparable limitation, but not including the geographic 
2locations of customers within the area which the alternative 
3retail electric supplier is certificated to serve. The 
4alternative retail electric supplier shall file the terms and 
5conditions of such service offering including the applicable 
6limitations with the Commission prior to making the service 
7offering available to customers.
8    (g) Nothing in this Section shall be construed as 
9preventing an alternative retail electric supplier, which is 
10an affiliate of, or which contracts with, (i) an industry or 
11trade organization or association, (ii) a membership 
12organization or association that exists for a purpose other 
13than the purchase of electricity, or (iii) another 
14organization that meets criteria established in a rule adopted 
15by the Commission, from offering through the organization or 
16association services at prices, terms and conditions that are 
17available solely to the members of the organization or 
18association.
19(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
 
20    (220 ILCS 5/16-119A)
21    Sec. 16-119A. Functional separation. 
22    (a) Within 90 days after the effective date of this 
23amendatory Act of 1997, the Commission shall open a rulemaking 
24proceeding to establish standards of conduct for every 
25electric utility described in subsection (b). To create 
 
 
10400SB0025ham004- 854 -LRB104 16098 AAS 29398 a

1efficient competition between suppliers of generating services 
2and sellers of such services at retail and wholesale, the 
3rules shall allow all customers of a public utility that 
4distributes electric power and energy to purchase electric 
5power and energy from the supplier of their choice in 
6accordance with the provisions of Section 16-104. In addition, 
7the rules shall address relations between providers of any 2 
8services described in subsection (b) to prevent undue 
9discrimination and promote efficient competition. Provided, 
10however, that a proposed rule shall not be published prior to 
11May 15, 1999.
12    (b) The Commission shall also have the authority to 
13investigate the need for, and adopt rules requiring, 
14functional separation between the generation services and the 
15delivery services of those electric utilities whose principal 
16service area is in Illinois as necessary to meet the objective 
17of creating efficient competition between suppliers of 
18generating services and sellers of such services at retail and 
19wholesale. After January 1, 2003, the Commission shall also 
20have the authority to investigate the need for, and adopt 
21rules requiring, functional separation between an electric 
22utility's competitive and non-competitive services.
23    (b-5) If there is a change in ownership of a majority of 
24the voting capital stock of an electric utility or the 
25ownership or control of any entity that owns or controls a 
26majority of the voting capital stock of an electric utility, 
 
 
10400SB0025ham004- 855 -LRB104 16098 AAS 29398 a

1the electric utility shall have the right to file with the 
2Commission a new plan. The newly filed plan shall supersede 
3any plan previously approved by the Commission pursuant to 
4this Section for that electric utility, subject to Commission 
5approval. This subsection only applies to the extent that the 
6Commission rules for the functional separation of delivery 
7services and generation services provide an electric utility 
8with the ability to select from 2 or more options to comply 
9with this Section. The electric utility may file its revised 
10plan with the Commission up to one calendar year after the 
11conclusion of the sale, purchase, or any other transfer of 
12ownership described in this subsection. In all other respects, 
13an electric utility must comply with the Commission rules in 
14effect under this Section. The Commission may promulgate rules 
15to implement this subsection. This subsection shall have no 
16legal effect after January 1, 2005.
17    (c) In establishing or considering the need for rules 
18under subsections (a) and (b), the Commission shall take into 
19account the effects on the cost and reliability of service and 
20the obligation of the utility to provide bundled service under 
21this Act. The Commission shall adopt rules that are a cost 
22effective means to ensure compliance with this Section.
23    (d) Nothing in this Section shall be construed as imposing 
24any requirements or obligations that are in conflict with 
25federal law.
26    (e) Notwithstanding anything to the contrary, an electric 
 
 
10400SB0025ham004- 856 -LRB104 16098 AAS 29398 a

1utility may market and promote the services, rates and 
2programs authorized by Sections 16-107, 16-107.8, and 16-108.6 
3of this Act.
4(Source: P.A. 99-906, eff. 6-1-17.)
 
5    (220 ILCS 5/16-126.2 new)
6    Sec. 16-126.2. Energy Reliability Corporation of Illinois.
7    (a) The General Assembly finds that:
8        (1) When Illinois restructured its electric market in 
9    1997, Illinois' largest 2 electric utilities unexpectedly 
10    elected to join 2 different regional transmission 
11    organizations (RTO), which effectively split the State 
12    into 2 zones.
13        (2) Illinois' bifurcated, existing RTO membership 
14    structure has created significant concerns related to 
15    delays in transmission build out, excessively long 
16    interconnection queue processes, favoring polluting 
17    generation resources over more cost-effective clean 
18    sources, inhibiting State policies, and inexplicably 
19    frustrating State efforts to address its resource adequacy 
20    needs through the development of new generation.
21        (3) The governance structures of PJM Interconnection, 
22    LLC (PJM) and the Midcontinent Independent System 
23    Operator, Inc. (MISO) have consistently failed to 
24    represent Illinois' interests.
25        (4) The Illinois Commerce Commission and the Illinois 
 
 
10400SB0025ham004- 857 -LRB104 16098 AAS 29398 a

1    Power Agency have the expertise to evaluate and present 
2    findings related to the costs and benefits of Illinois 
3    pursuing any one of the following 3 options: (1) 
4    establishing a single, State-specific Independent System 
5    Operator (ISO); (2) consolidating Illinois' existing 
6    bifurcated RTO membership structure into one existing RTO; 
7    or (3) maintaining the existing bifurcated RTO structure.
8    (b) The Commission and the Illinois Power Agency shall 
9conduct a joint study and publish the findings of the study to 
10evaluate whether (1) establishing a single State-operated ISO; 
11(2) consolidating this State's bifurcated RTO membership into 
12an existing RTO; or (3) maintaining the existing bifurcated 
13RTO structure, would be consistent with the State's goals and 
14would maximize benefits to State businesses and residents. As 
15a part of this evaluation, the Commission and the Illinois 
16Power Agency shall analyze whether it would be feasible and 
17practical for this State to pursue any of the options 
18described in this subsection (b).
19    (c) The Commission and the Illinois Power Agency shall 
20examine the costs and benefits, over a 20-year period, of this 
21State pursuing any of the options described in subsection (b). 
22The study shall examine the costs and benefits of such 
23participation over 20 years. The study shall examine the costs 
24and benefits to State ratepayers, including, but not limited 
25to, consideration of the regulatory, reliability, operational, 
26and competitive benefits of this State participating in one 
 
 
10400SB0025ham004- 858 -LRB104 16098 AAS 29398 a

1existing RTO, as compared to participating in a State-specific 
2ISO, or continuing to participate in the current bifurcated 
3RTO structure. The costs and benefits evaluated should include 
4resource adequacy benefits, resilience, affordability, equity, 
5the impact on the environment, and the general health, safety, 
6and welfare of the People of this State.
7    The study shall, at a minimum, include the following, and 
8it may consider or suggest additional or alternative items:
9        (1) the appropriate timetable to (i) establish and 
10    effectively transition to a State-specific ISO, or (ii) 
11    consolidate into an existing RTO, taking into account how 
12    that schedule could support the emission reduction 
13    timeline established in Section 9.15 of the Environmental 
14    Protection Act; and
15        (2) the appropriate benefits and costs to consider, 
16    such as the regulatory, reliability, operational, and 
17    competitive benefits, including, but not limited to:
18            (i) capacity market benefits and costs of 
19        separating from the PJM and MISO territories versus 
20        those of the status quo;
21            (ii) transmission benefits and costs of separating 
22        from the PJM and MISO territories versus those of a 
23        State-specific ISO;
24            (iii) the legal, correct, and appropriate exit 
25        fees for leaving regional transmission organizations;
26            (iv) managing the State's energy resources to 
 
 
10400SB0025ham004- 859 -LRB104 16098 AAS 29398 a

1        supply electricity throughout the State versus the 
2        existing bifurcated structure;
3            (v) the potential improvements in interconnection 
4        queue speed versus the current lengthy delays in the 
5        PJM and MISO processes;
6            (vi) the potential for a State-specific ISO to 
7        more effectively value and enable resources, such as 
8        storage of renewable resources, demand response, 
9        energy efficiency, and the adoption of new 
10        technologies and applications, versus the current PJM 
11        and MISO structures; and
12            (vii) an evaluation of any improved ability for 
13        the State to meet its goals and objectives in a new 
14        State-specific ISO versus the existing structure.
15        After the completion of the study, if the Commission 
16    and the Illinois Power Agency find that the results of the 
17    study were overall beneficial to the citizens of this 
18    State, then the Commission and the Illinois Power Agency 
19    may conduct and publish an additional ISO policy study 
20    that explores the steps required to establish a 
21    State-specific ISO. The Governor and members of the 
22    General Assembly may request an additional ISO policy 
23    study, or any other follow-up study, regardless of the 
24    outcome of the original study. An additional study may, 
25    for example, investigate the steps required for this State 
26    to consolidate into one existing RTO.
 
 
10400SB0025ham004- 860 -LRB104 16098 AAS 29398 a

1        The additional ISO policy study shall investigate a 
2    governance structure and design that would enable State 
3    policy independence and more fully support State resource 
4    adequacy and reliability while also complying with FERC 
5    Order 2000. The additional ISO study may investigate how a 
6    State-specific ISO would be able to demonstrate the 
7    following issues, including, but not limited to:
8        (i) independence from market participants;
9        (ii) an appropriate scope and regional configuration;
10        (iii) possession of operational authority for all 
11    transmission facilities under the control of the 
12    State-specific ISO;
13        (iv) exclusive authority to maintain short-term 
14    reliability of the grid;
15        (v) tariff administration and design;
16        (vi) congestion management;
17        (vii) management of parallel path flows;
18        (viii) provision of last resort for ancillary 
19    services;
20        (ix) development of an Open Access Same-time 
21    Information System (OASIS);
22        (x) market monitoring; and
23        (xi) responsibility for planning and expanding 
24    facilities under its control.
25    (d) The Commission and the Illinois Power Agency shall 
26retain the services of technical and policy experts with 
 
 
10400SB0025ham004- 861 -LRB104 16098 AAS 29398 a

1relevant fields of expertise. Given the critical and rapid 
2actions required under this Section, the Commission and the 
3Illinois Power Agency may procure the services of any 
4facilitator, expert, or consultant to assist with the 
5implementation of this Section. Such procurement is exempt 
6from the requirements of the Illinois Procurement Code under 
7Section 20-10 of the Illinois Procurement Code. The Commission 
8and the Illinois Power Agency may jointly determine that the 
9cost of any contract pursuant to this Section may be borne 
10initially by the relevant electric public utilities, but shall 
11be recovered as an expense through normal ratemaking 
12procedures. The Illinois Finance Authority, the Illinois 
13Environmental Protection Agency, and the Department of 
14Commerce and Economic Opportunity shall provide support to and 
15consult with the Commission and the Illinois Power Agency when 
16requested. The Commission and the Illinois Power Agency may 
17consult with other State agencies, commissions, or task forces 
18as needed.
19    (e) The Commission and the Illinois Power Agency may 
20solicit information, including confidential or proprietary 
21information, from entities likely to be impacted by the 
22creation of a State-specific ISO. The Commission and the 
23Illinois Power Agency may consult with and seek assistance 
24from (i) Independent System Operators in other states, such as 
25Texas, California, and New York, (ii) federal agencies, such 
26as the Federal Energy Regulatory Commission, and (iii) the 
 
 
10400SB0025ham004- 862 -LRB104 16098 AAS 29398 a

1regional transmission organizations PJM and MISO. Any 
2information designated as confidential or proprietary 
3information by the entity providing the information shall be 
4kept confidential by the Commission, its consultants, and its 
5contractors, and the Illinois Power Agency, its consultants, 
6and its contractors, and is not subject to disclosure under 
7the Freedom of Information Act. The Office of the Attorney 
8General shall have access to, and maintain the confidentiality 
9of, such information pursuant to Section 6.5 of the Attorney 
10General Act.
11    (f) The Commission and the Illinois Power Agency shall 
12publish the joint final policy study no later than December 1, 
132026 and suitable copies shall be delivered to the Governor 
14and members of the General Assembly.    
 
15    (220 ILCS 5/16-145 new)
16    Sec. 16-145. Powering Up Illinois.
17    (a) For the purposes of this Section:
18    "Electric utility" means an electric utility serving more 
19than 500,000 customers in this State.
20    "Energization" and "energize" means the connection of new 
21electric vehicle charging infrastructure projects over 5 
22megawatts to the electrical grid or upgrading electrical 
23capacity to provide adequate service to such electric vehicle 
24charging infrastructure projects. "Energization" and 
25"energize" do not include activities related to connecting 
 
 
10400SB0025ham004- 863 -LRB104 16098 AAS 29398 a

1electricity supply resources.
2    "Energization time period" means the period of time that 
3begins when the electric utility receives a substantially 
4complete energization project application and ends when the 
5electric service associated with the project is installed and 
6energized, consistent with the service obligations set forth 
7in the Section 8-101 of the Public Utilities Act.
8    (b) The Commission shall adopt rules to establish and 
9track reasonable average and maximum target energization time 
10periods for energization projects. Such rules shall, at a 
11minimum, establish the following:
12        (1) reasonable average and maximum target energization 
13    time periods. The targets shall ensure that work is 
14    completed in a safe and reliable manner that minimizes 
15    delay in meeting the date requested by a customer for 
16    completion of the energization project to the greatest 
17    extent possible. The targets may vary based on factors, 
18    including, but not limited to, customer class, size of the 
19    project, the complexity and magnitude of the work 
20    required, and uncertainties regarding the readiness of the 
21    customer project needing energization. The targets may 
22    also recognize any factors beyond the electric utility's 
23    control;
24        (2) requirements for an electric utility to report to 
25    the Commission, at least annually, in order to track and 
26    improve electric utility performance. The report shall, at 
 
 
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1    a minimum, include the average, median, and standard 
2    deviation time between receiving an application for 
3    electrical service and energizing the electrical service, 
4    and detailed explanations for energization time periods 
5    that exceed the target maximum for energization projects, 
6    constraints and obstacles to each type of energization, 
7    including, but not limited to, funding limitations, 
8    qualified staffing availability, or equipment 
9    availability, and any other information that the 
10    Commission, in its discretion, concludes that such reports 
11    should contain; and
12        (3) procedures for customers to report energization 
13    delays to the Commission.
14    (c) If an electric utility's average time period for 
15energization in a calendar year exceeds the Commission's 
16target averages or if an electric utility has exceeded the 
17Commission's target maximums as established by rule, the 
18electric utility shall include in its report pursuant to rules 
19adopted under paragraph (2) of subsection (b) a detailed 
20remedial plan for meeting the targets in the future. The 
21Commission may require modification to the electric utility's 
22remedial plan to ensure that the electric utility meets 
23targets promptly.
24    (d) Data reported by electric utilities shall be 
25anonymized or aggregated to the extent necessary to prevent 
26identifying individual customers. The Commission shall make 
 
 
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1all such reports publicly available.
2    (e) In addition to requiring remedial plans pursuant to 
3subsection (c) of this Section, the Commission may require an 
4electric utility to take any remedial actions necessary to 
5achieve the Commission's targets.    
 
6    (220 ILCS 5/16-201 new)
7    Sec. 16-201. Integrated resource plan development.
8    (a) The General Assembly hereby finds that:
9        (1) In 2021, Illinois set itself on the path to a clean 
10    energy future that would produce the least amount of 
11    carbon and copollutant emissions while ensuring adequate, 
12    reliable, affordable, efficient, and environmentally 
13    sustainable electric service at the lowest total cost over 
14    time and in a manner that benefits the Illinois economy 
15    and workforce and improves the quality of life, including 
16    environmental health, for all its citizens.
17        (2) In the ensuing years, Illinois has created a 
18    strong economic environment that has led to the 
19    revitalization and expansion of its manufacturing sector 
20    and has made Illinois an attractive place for the 
21    technology industry to locate new data and quantum 
22    computing centers. These developments have led to the 
23    creation of good-paying jobs for working families.
24        (3) The unforeseen growth in the manufacturing and 
25    technology sectors will likely lead to a dramatic increase 
 
 
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1    in electricity demand over time.
2        (4) The long interconnection times and the capacity 
3    market structures enacted by the 2 regional transmission 
4    organizations that Illinois is split between further 
5    exacerbate the potential for an imbalance between 
6    electricity supply and demand.
7        (5) The new sources of load growth from the 
8    manufacturing and technology sectors combined with 
9    external challenges require a more nimble and responsive 
10    administrative approach to effectively address future 
11    resource adequacy challenges.
12        (6) The Illinois agencies that oversee and implement 
13    Illinois energy policy must have the ability to (i) fully 
14    understand current and future resource adequacy needs, 
15    (ii) plan for what resources could be utilized to address 
16    such needs, (iii) be able to coordinate, modify, expand, 
17    and direct all of Illinois' existing energy programs and 
18    policies so as to address any resource adequacy or 
19    reliability concerns, and (iv) direct the development of 
20    new energy programs and policies in order meet resource 
21    adequacy and reliability needs without the need for 
22    additional legislative action.
23    (b) The purpose of this Section is to ensure that the 
24Commission, the agencies, electric utilities supplying 
25electric service in Illinois, stakeholders, market 
26participants, and policymakers have a common set of data and 
 
 
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1information regarding the State's electricity resource needs 
2in order to plan for sufficient electricity resources to serve 
3Illinois customers in a manner that is adequate, safe, 
4reliable, affordable, efficient, environmentally sustainable, 
5at the lowest cost over time, and consistent with the energy 
6policy goals of the State, including, but not limited to, the 
7clean energy policy established by Public Act 102-662. To that 
8end, this Section establishes a requirement that the agencies 
9prepare an integrated resource plan and submit such plan to 
10the Commission consistent with this Section for the 
11Commission's review and approval after an opportunity for 
12notice and hearing.
13    (c) Unless otherwise specified, as used in this Section, 
14the following terms shall have the following meanings:
15        (1) "Advanced transmission technologies" means 
16    technologies, tools, and software that improve power flows 
17    over transmission systems and lines. "Advanced 
18    transmission technologies" includes, but is not limited 
19    to, the following:
20            (i) technology that dynamically adjusts the rated 
21        capacity of transmission lines based on real-time 
22        conditions;
23            (ii) advanced power flow controls used to actively 
24        control the flow of electricity across transmission 
25        lines to optimize usage or relieve congestion;
26            (iii) software or hardware used to identify 
 
 
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1        optimal transmission grid configurations or enable 
2        routing power flows around congestion points; and
3            (iv) advanced transmission line conductors that 
4        have a direct current electrical resistance at least 
5        10% lower than existing conductors of a similar 
6        diameter on the transmission system.
7        (2) "Agencies" means the Illinois Commerce Commission 
8    Staff, the Illinois Power Agency, the Illinois Finance 
9    Authority, the Illinois Environmental Protection Agency, 
10    and any consultants those agencies retain, including, but 
11    not limited to, the consultant retained by the Commission 
12    pursuant to subsection (j) of this Section and the 
13    consultant retained by the Illinois Power Agency pursuant 
14    to paragraph (1) of subsection (a) of Section 1-75 of the 
15    Illinois Power Agency Act.
16        (3) "Clean energy" means energy generation that 
17    either:
18            (A) emits no on-site SO2, NOx, mercury, or any 
19        other regulated pollutants; or
20            (B) as shown through pollution control 
21        technologies, has reduced a generator's CO2 emissions 
22        by 90% compared to what the generator would have 
23        otherwise emitted and that has CO2 emissions less than 
24        130 lb/MWh.
25        (4) "Regional transmission organization" or "RTO" 
26    means PJM Interconnection, LLC (PJM) and the Midcontinent 
 
 
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1    Independent System Operator, Inc. (MISO) or the regional 
2    transmission organization or independent system operator 
3    of which the electric utility is a member or would be a 
4    member, given the location of the electric utility's 
5    customers, if it were required to be a member.
6    (d) The agencies, coordinated by Commission staff, shall 
7compile and propose an integrated resource plan in compliance 
8with this Section. The agencies may consult with each electric 
9utility that has more than 500,000 electric retail customers 
10in developing the plan and the plan shall consider any 
11necessary interactions between RTO zones in the State. 
12Commission staff shall submit the initial integrated resource 
13plan to the Commission no later than November 15, 2026, the 
14second integrated resource plan to the Commission no later 
15than September 30, 2029, and each subsequent plan to the 
16Commission every 4 years thereafter no later than September 30 
17of the applicable year. For the first integrated resource plan 
18due on November 15, 2026, the agencies shall take into account 
19the resource adequacy report prepared pursuant to subsection 
20(o) of Section 9.15 of the Environmental Protection Act and 
21shall specifically address any and all divergences from the 
22analysis and conclusions in the report. At any time after the 
23submission of a plan, the agencies may submit an update to the 
24plan if the agencies believe that a material change in the 
25inputs or conclusions of the plan is warranted. The agencies 
26shall notify the Commission as soon as practicable of the 
 
 
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1material change and the potential update to the plan. The 
2Commission shall publish the integrated resource plan on its 
3website.
4    (e) An alternative retail electric supplier shall provide 
5information related to the resource needs of its customers 
6located in an electric utility's service territory as 
7requested by the agencies or the Commission to compile and 
8develop the plan required by this Section.
9    (f) Commission staff shall lead the agencies in the 
10development of the integrated resource plan to ensure that a 
11plan submitted pursuant to this Section includes a detailed 
12analysis of the following:
13        (1) an evaluation of the future electric resource 
14    needs in each electric utility's service area for periods 
15    of at least 5, 10, 15, and 20 years such that the plan 
16    coincides with the timelines established in Section 9.15 
17    of Title II of the Environmental Protection Act and is 
18    designed to support those standards to the maximum extent 
19    practicable on the schedule established therein;
20        (2) peak demand and energy usage forecasts, such that 
21    the plan:
22            (i) contains no fewer than 3 scenarios of (i) 
23        forecasted peak demand, (ii) net peak demand if 
24        different from peak demand, (iii) non-coincidental 
25        peak demand, and (iv) energy usage, to capture a 
26        reasonable range of forecasts based on historic trends 
 
 
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1        and a diverse range of more conservative to high load 
2        growth based on reasonable projections. The scenarios 
3        should consider estimates of peak demand corresponding 
4        to seasons or other applicable time periods as defined 
5        by the regional transmission organization in which 
6        this State's electric utilities are a member;
7            (ii) reflects known changes in facility and 
8        appliance codes and standards;
9            (iii) reflects load reductions from 
10        State-sponsored programs;
11            (iv) reflects load reductions from programs 
12        sponsored by electric utilities;
13            (v) reflects load reductions from aggregators of 
14        retail customers that can be applied to the host 
15        load-serving entity's resource adequacy requirement;
16            (vi) reflects load reductions from any other 
17        sources including out-of-state programs that could 
18        influence load;
19            (vii) reflects expected adoption of other 
20        distributed energy resources, including 
21        behind-the-meter generation; and
22            (viii) includes any additional sensitivities as 
23        determined by the agencies;
24        (3) an analysis of all generation and energy resource 
25    options available to meet the range of load forecasts with 
26    a focus on the first period of at least 5 years covered by 
 
 
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1    the plan, including an analysis of existing supply found 
2    within each electric utility's service area and new supply 
3    expected to come online across that period of at least 5 
4    years, such that the plan shall consider the following:
5            (i) the current and projected status of electric 
6        resource adequacy throughout the State from sources 
7        the agencies deem reasonable;
8            (ii) a range of resource options that can be 
9        deployed at a reasonable scale, that provide clean 
10        energy to the maximum extent practicable, and that 
11        include generation and energy resources on both the 
12        demand-side and supply-side;
13            (iii) developing technologies that will be 
14        commercially viable during the period of analysis;
15            (iv) reflect reasonable assumptions for capital 
16        and operating costs and the performance of resource 
17        technologies. The calculation of resource costs shall 
18        include reasonable expected costs for transmission 
19        interconnection and network upgrades made necessary by 
20        the addition of each resource; and
21            (v) appropriate considerations for implementation, 
22        such as:
23                (A) timelines for implementation, including, 
24            but not limited to, siting, permitting, 
25            engineering, transmission interconnection, and the 
26            time it takes to modify existing programs or 
 
 
10400SB0025ham004- 873 -LRB104 16098 AAS 29398 a

1            create new programs and put them into operation;
2                (B) recommendations for how new clean 
3            resources should be developed to respond to 
4            resource adequacy challenges; and
5                (C) any other requirements for implementation;
6        (4) confirmation that the resource adequacy and 
7    reliability requirements employed in the plan meet the 
8    following conditions:
9            (i) the plan must reflect planning reserve margin 
10        requirements established by the corresponding RTO, 
11        other resource adequacy requirements set by an 
12        applicable authority as authorized by the State, or 
13        another standard chosen by the Commission; and
14            (ii) the integrated resource plan may reflect a 
15        supplemental reliability analysis, including the 
16        evaluation of reliability metrics not prescribed by an 
17        RTO or other applicable authority as authorized by the 
18        State;
19        (5) consistency with existing State and federal 
20    environmental laws and policies, including, but not 
21    limited to, the decarbonization goals set forth in Section 
22    9.15 of the Illinois Environmental Protection Act. The 
23    plan may consider potential changes in State and federal 
24    environmental laws and policies. The plan must provide 
25    expected emissions for CO2, SO2, NOx, mercury, and any 
26    other regulated pollutants in order to analyze the impact 
 
 
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1    of retirement timelines on emissions reductions. The plan 
2    must be consistent with the State's other clean energy 
3    goals and targets, including, but not limited to, its 
4    renewable portfolio standard, its energy efficiency 
5    portfolio standard, the carbon mitigation credit program, 
6    and its energy storage system portfolio standard. The plan 
7    shall include an analysis of the following:
8            (i) the State's current progress toward its 
9        renewable energy resource development goals, its 
10        storage development goals, and its energy efficiency 
11        and demand-response goals, as well as the pace of the 
12        development of renewables, energy storage, including 
13        distributed storage, the deployment of virtual power 
14        plants, and demand-response utilization; and
15            (ii) the status of the State's CO2e and copollutant 
16        emissions reductions and its current status and 
17        progress toward developing emerging clean energy 
18        technologies;
19        (6) consideration of the following additional issues:
20            (i) an integrated resource plan shall be designed 
21        to collectively meet all of Illinois' energy policy 
22        goals and shall describe:
23                (A) how the plan complies with the various 
24            requirements of State energy policy;
25                (B) the assumptions and analytical methods 
26            used in the plan;
 
 
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1                (C) recommendations for how State policy 
2            should serve to facilitate the development of new 
3            resources;
4                (D) the impacts of the plan on customer costs, 
5            including net present value costs relative to 
6            alternatives; and
7                (E) how the plan improves energy equity within 
8            environmental justice and equity investment 
9            eligible communities, as defined by the Energy 
10            Transition Act, including, but not limited to, 
11            reducing energy burden, ensuring affordability of 
12            electric utility bills and uninterruptible 
13            essential utility service, and reducing barriers 
14            to accessing renewable energy;    
15            (ii) an integrated resource plan shall include a 
16        discussion of the steps needed to implement the plan, 
17        including, but not limited to, options and steps to 
18        bring on new or increased energy generated from any 
19        recommended resources for the 5 years after the plan 
20        would be implemented, that align with State clean 
21        energy policy;
22            (iii) an integrated resource plan shall consider 
23        the information and conclusions set forth in the 
24        renewable energy access plan developed in accordance 
25        with Section 8-512, including, but not limited to, 
26        information concerning the locations of renewable 
 
 
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1        energy access plan zones, considerations of advanced 
2        transmission technologies to increase efficiencies, 
3        and different transmission planning options and cost 
4        allocations;
5            (iv) an integrated resource plan may consider the 
6        impacts of future or anticipated changes in State and 
7        federal energy laws and policies; and
8            (v) any solutions for any additional conclusions;
9        (7) if the agencies choose, portfolio-optimization 
10    results based on the following:
11            (i) capacity expansion and production cost 
12        modeling consistent with the conditions and 
13        constraints set forth in this Section;
14            (ii) optimized candidate portfolios that align 
15        with the load-growth scenarios described in paragraph 
16        (2) of subsection (f) of this Section and any 
17        additional portfolios chosen by the agencies to 
18        reflect alternative policy or technology assumptions;
19            (iii) a comparison of total system cost on a 
20        net-present-value basis, customer rate and bill 
21        impacts, risk metrics, including, but not limited to, 
22        cost variability under fuel-price and load shocks, 
23        emissions trajectories, and key reliability 
24        indicators; and
25            (iv) an identification of a preferred portfolio or 
26        portfolios that best satisfy the objectives of 
 
 
10400SB0025ham004- 877 -LRB104 16098 AAS 29398 a

1        affordability, reliability, equity, and emission 
2        reduction and a narrative explanation of why the 
3        portfolio is recommended; and
4    The agencies may request that PJM and MISO, or their 
5respective successor organizations, conduct a resource 
6adequacy and reliability study. The study shall include the 
7megawatt amount of energy storage capacity that would maintain 
8resource adequacy during the study period to fully meet the 
9requirements for CO2e and copollutant emissions reductions 
10under Public Act 102-662 that would not otherwise be met by the 
11interconnection queue and without large transmission upgrades, 
12including maintaining sufficient in-State capacity to meet the 
13zonal requirements of MISO Zone 4 or the PJM ComEd Zone. The 
14study shall also identify recommended geographic locations for 
15new storage and clean energy to mitigate local reliability 
16risks, including at or near the sites of any generator 
17deactivations to maximize the efficient utilization of 
18existing infrastructure.    
 
19    (220 ILCS 5/16-202 new)
20    Sec. 16-202. Integrated resource plan review and approval.
21    (a) The Commission shall enter its order approving or 
22approving with modifications an integrated resource plan 
23within 180 days after the agencies filing the plan and any 
24companion reports or other information. The Commission may 
25extend the period of review of the plan for no more than an 
 
 
10400SB0025ham004- 878 -LRB104 16098 AAS 29398 a

1additional 180 days.
2    (b) The Commission may approve a plan or a modified plan 
3and authorize its implementation only if, after notice and 
4hearing, including the conduct of discovery and taking of 
5evidence, it finds that the plan:
6        (1) addresses any resource adequacy challenges in the 
7    5 years immediately following approval of the plan, while 
8    also taking into account the 10 years following the plan;
9        (2) prepares the State to best address issues of 
10    resource adequacy at the least amount of CO2e and 
11    copollutant emissions;
12        (3) considers the emissions' impacts on environmental 
13    justice communities while taking into account all 
14    applicable labor and equity standards;
15        (4) supports the provisioning of adequate, reliable, 
16    affordable, efficient, and environmentally sustainable 
17    electric service at the lowest total cost over time; and
18        (5) utilizes the expansion of renewable energy, energy 
19    storage, virtual power plants and distributed energy 
20    storage, energy efficiency, demand response, time-of-use 
21    rates or other mechanisms designed to manage peak load, 
22    transmission development, carbon mitigation credits or any 
23    other clean energy strategies to the maximum extent 
24    practicable to resolve any identified resource adequacy 
25    shortfall or reliability violation in a cost-effective, 
26    affordable, timely, and clean manner.
 
 
10400SB0025ham004- 879 -LRB104 16098 AAS 29398 a

1    (c) The Commission may, as a part of its decision to 
2approve a plan or modified plan and to the extent consistent 
3with the uniform allocation of costs required under subsection 
4(k) of Section 16-108, order changes to existing programs, 
5direct specific actions within existing programs including the 
6authorization to support the expansion of an existing program, 
7including, but not limited to:
8        (1) any of the following plans or programs designed to 
9    increase the amount of generation and capacity available:
10            (i) the Long-Term Renewable Resources Procurement 
11        Plan, including programs and procurements authorized 
12        through that Plan, and to increase the limitations 
13        placed on the procurement of renewable energy 
14        resources established pursuant to subparagraph (E) of 
15        paragraph (1) of subsection (c) of Section 1-75 of the 
16        Illinois Power Agency Act in order to increase, 
17        direct, or adjust procurements of renewable energy 
18        resources to support new renewable energy projects;
19            (ii) the Energy Storage Resources Procurement 
20        Plan, including programs and procurements authorized 
21        through that Plan, and to increase the procurement of 
22        energy storage established pursuant to subsection 
23        (d-20) of Section 1-75 of the Illinois Power Agency 
24        Act in order to increase or adjust procurements for 
25        new energy storage;
26            (iii) the carbon mitigation credit procurement 
 
 
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1        plans established pursuant to subsection (d-10) of 
2        Section 1-75 of the Illinois Power Agency Act in order 
3        to preserve existing carbon-free energy resources, 
4        including extending or expanding carbon mitigation 
5        credit contract awards in accordance with a new 
6        schedule of baseline costs;
7            (iv) the Illinois Power Agency's annual 
8        electricity procurement plans established pursuant to 
9        paragraph (2) of subsection (d) of Section 16-111.5, 
10        including modification of the products to be procured 
11        and allowing for costs associated with the purchase of 
12        new or additional products to be socialized across all 
13        retail customers or all load-serving entities, as 
14        applicable; and
15            (v) any additional programs designed to procure 
16        appropriate sources of new clean energy and capacity 
17        resources, including any associated clean attribute 
18        credits; and
19        (2) any of the following designed to manage energy 
20    demand, including, but not limited to:
21            (i) extending or expanding the energy efficiency 
22        programs implemented by electric utilities and the 
23        limitation on the amount of energy efficiency and 
24        demand-response measures implemented pursuant to 
25        Section 8-103B in order to gain increased load 
26        reductions; and
 
 
10400SB0025ham004- 881 -LRB104 16098 AAS 29398 a

1            (ii) the Multi-Year Integrated Grid Plans 
2        implemented by electric utilities pursuant to Section 
3        16-105.17 in order to extend or expand programs 
4        related to peak load management and reduction, 
5        including, but not limited to, virtual power plants, 
6        front of the meter distributed storage, demand 
7        response, and time-of-use rates.
8    (d) If all of the changes made to the programs pursuant to 
9this Section would reasonably be insufficient to balance 
10supply and demand and avoid a resource adequacy shortfall, 
11then the Commission may delay, in whole or in part, the CO2e    
12and copollutant emissions reductions requirements found in 
13Section 9.15 of the Environmental Protection Act but only to 
14the minimum extent and duration necessary to address the 
15resource adequacy shortfall needs of the State. If the 
16Commission finds that reducing or delaying the emissions 
17reductions requirements is necessary, despite any or all of 
18the changes made pursuant to this Section, then it shall also 
19include in its final order recommendations to the General 
20Assembly on what additional policies may be adopted that could 
21avoid future modifications to the emissions reductions.
22    (e) Unless otherwise specified by the Commission, the 
23order approving the plan or modified plan shall become 
24effective January 1 of the calendar year immediately following 
25the issuance of the order. The agencies, electric utilities, 
26and any other impacted entities shall comply with any of the 
 
 
10400SB0025ham004- 882 -LRB104 16098 AAS 29398 a

1Commission's orders, and when required seek approval from the 
2Commission and make any required modifications to their plans, 
3programs, or related initiatives in a manner consistent with 
4the process and timing for those changes as outlined in the 
5approved plans or, if none is specified, as soon as 
6practicable. If the integrated resource plan approved by the 
7Commission contains recommendations that are outside the 
8Commission's authority, the Commission shall communicate any 
9such recommendations to the Governor and the General Assembly.
10    (f) Given the critical and rapid actions required under 
11this Section, the Commission may procure the services of any 
12facilitator, expert, or consultant, including the procurement 
13monitor retained by the Commission pursuant to paragraph (2) 
14of subsection (c) of Section 16-111.5. Such procurement is 
15exempt from the requirements of the Illinois Procurement Code, 
16pursuant to Section 20-10 of that Code.
17    (g) Costs that are prudently and reasonably incurred by 
18electric utilities to comply with the requirements of this 
19Section shall be recovered and shall be excluded from the 
20calculation performed under paragraph (6) of subsection (f) of 
21Section 16-108.18. Nothing in the Commission's order directing 
22changes to a prior approved plan as enumerated in this Section 
23shall be the sole basis for a finding of imprudence or 
24unreasonableness or the lack of use or usefulness of any 
25investment or expenditure.    
26    (h) If the Commission's final order under this Section 
 
 
10400SB0025ham004- 883 -LRB104 16098 AAS 29398 a

1includes the approval of rate increases through the expansion 
2of existing programs, the creation of new programs, or the 
3increase of limitations placed on procurements as described 
4under paragraphs (1) and (2) of subsection (c), the Commission 
5shall submit notice to the General Assembly of the increases 
6included in the final order, including the estimated monthly 
7cost impact on customers and the expected costs savings or 
8benefits of such actions. After receipt of a notice, any 
9member of the General Assembly may introduce in the General 
10Assembly a joint resolution stating that the General Assembly 
11desires to suspend the rate increases, or suspend a portion of 
12the rate increases, identified in the final order and 
13specifying the rationale for the General Assembly's 
14determination.
15        (1) If the General Assembly passes a joint resolution 
16    under this subsection (h) that takes effect prior to the 
17    effective date of the Commission's final order, the 
18    General Assembly shall send notice to the Commission of 
19    the resolution, and the Commission shall suspend its final 
20    order. Within 30 days of receipt of the General Assembly's 
21    notice, the Commission shall reopen the docket approving 
22    the plan or modified plan in order to take into account the 
23    General Assembly's reduction or elimination of the rate 
24    increases. The Commission shall approve the modified plan 
25    within 120 days of reopening the docket, including the 
26    conduct of discovery and the taking of evidence, and send 
 
 
10400SB0025ham004- 884 -LRB104 16098 AAS 29398 a

1    notice to the General Assembly of its modified plan. The 
2    General Assembly may rescind its desire to suspend the 
3    rate increases, or suspend a portion of the rate 
4    increases, by adoption of a subsequent joint resolution by 
5    each chamber of the General Assembly within 30 days of 
6    receipt of the Commission's notice that would put into 
7    effect the Commission's original final order.
8        (2) If the General Assembly fails to pass a joint 
9    resolution under this subsection (h) prior to the 
10    effective date of the Commission's final order, the 
11    associated rate increases shall go into effect pursuant to 
12    the schedule specified in the Commission's final order 
13    approving the plan or modified plan.    
14    (i) The Commission may adopt rules to implement the 
15requirements of this Section.    
 
16    (220 ILCS 5/17-900)
17    Sec. 17-900. Customer self-generation of electricity.
18    (a) The General Assembly finds and declares that municipal 
19systems and electric cooperatives shall continue to be 
20governed by their respective governing bodies, but that such 
21governing bodies should recognize and implement policies to 
22provide the opportunity for their residential and small 
23commercial customers who wish to self-generate electricity and 
24for reasonable credits to customers for excess electricity, 
25balanced against the rights of the other non-self-generating 
 
 
10400SB0025ham004- 885 -LRB104 16098 AAS 29398 a

1customers. This includes creating consistent, fair policies 
2that are accessible to all customers and transparent, fair 
3processes for raising and addressing any concerns.
4    (b) Customers have the right to install renewable 
5generating facilities to be located on the customer's premises 
6or customer's side of the billing meter and that are intended 
7primarily to offset the customer's own electrical requirements 
8and produce, consume, and store their own renewable energy 
9without discriminatory repercussions from an electric 
10cooperative or municipal system. This includes a customer's 
11rights to:
12        (1) generate, consume, and deliver excess renewable 
13    energy to the distribution grid and reduce his or her use 
14    of electricity obtained from the grid;
15        (2) use technology to store energy at his or her 
16    residence;
17        (3) interconnect his or her electrical system that 
18    generates renewable energy, stores energy, or any 
19    combination thereof, with the electricity meter on the 
20    customer's premises that is provided by an electric 
21    cooperative or municipal system:
22            (A) in a timely manner;
23            (B) in accordance with requirements established by 
24        the electric cooperative or municipal utility to 
25        ensure the safety of utility workers; and
26            (C) after providing written notice to the electric 
 
 
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1        cooperative or municipal utility system providing 
2        service in the service territory, installing a 
3        nomenclature plate on the electrical meter panel and 
4        meeting all applicable State and local safety and 
5        electrical code requirements associated with 
6        installing a parallel distributed generation system; 
7        and
8        (4) receive fair credit for excess energy delivered to 
9    the distribution grid; and
10        (5) for residential and small commercial customers, 
11    interconnect renewable energy systems sized up to and 
12    including 25 kW AC.
13    (c) The policies of municipal systems and electric 
14cooperatives regarding self-generation and credits for excess 
15electricity may reasonably differ from those required of other 
16entities by Article XVI of the Public Utilities Act or other 
17Acts. The credits must recognize the value of self-generation 
18to the distribution grid and benefits to other customers.
19    (c-5) The policies of municipal systems and electric 
20cooperatives regarding self-generation and credits for excess 
21electricity shall not require customers to name the municipal 
22system or electric cooperative as an additional insured on the 
23customer's insurance policies or have any minimum liability 
24limit requirement in connection with the installation and 
25operation of renewable generating facilities if the renewable 
26generating facilities meet the safety standards listed in the 
 
 
10400SB0025ham004- 887 -LRB104 16098 AAS 29398 a

1applicable interconnection agreement and the contractor used 
2to install the renewable generating facilities is licensed and 
3possesses commercial general liability insurance coverage of 
4at least $1,000,000 per occurrence and $2,000,000 in the 
5aggregate per year.    
6    (d) Within 180 days after this amendatory Act of the 102nd 
7General Assembly, each electric cooperative and municipal 
8system shall update its policies for the interconnection and 
9fair crediting of customer self-generation and storage if 
10necessary, to comply with the standards of subsection (b) of 
11this Section. Each electric cooperative and municipal system 
12shall post its updated policies to a public-facing area of its 
13website.
14    (e) An electric cooperative or municipal system customer 
15who produces, consumes, and stores his or her own renewable 
16energy shall not face discriminatory rate design, fees or 
17charges, treatment, or excessive compliance requirements that 
18would unreasonably affect that customer's right to 
19self-generate electricity as provided for in this Section.
20    (f) An electric cooperative or municipal utility system 
21customer shall have a right to appeal any decision related to 
22self-generation and storage that violates these rights to 
23self-generation and non-discrimination pursuant to the 
24provisions of this Section through a complaint under the 
25Administrative Review Law or similar legal process.
26(Source: P.A. 102-662, eff. 9-15-21.)
 
 
 
10400SB0025ham004- 888 -LRB104 16098 AAS 29398 a

1    (220 ILCS 5/20-140 new)
2    Sec. 20-140. Interconnection Working Group.
3    (a) The Commission shall establish an Interconnection 
4Working Group. The Working Group shall include representatives 
5from electric utilities, developers of renewable electric 
6generating facilities, representatives of new large loads 
7seeking grid interconnection, other industries that regularly 
8apply for interconnection with the electric utilities as 
9appropriate, representatives of distributed generation 
10customers, the Commission staff, and other stakeholders with a 
11substantial interest in the topics addressed by the 
12Interconnection Working Group.
13    (b) The Interconnection Working Group shall address at 
14least the following issues in relation to new generation and 
15new large loads:
16        (1) the cost of and the best available technology for 
17    interconnection and metering, including the 
18    standardization and publication of standard costs;
19        (2) transparency, accuracy, and use of the 
20    distribution interconnection queue and hosting capacity 
21    maps;
22        (3) distribution system upgrade cost avoidance through 
23    use of advanced inverter functions, energy storage, and 
24    load management;
25        (4) predictability of the queue management process and 
 
 
10400SB0025ham004- 889 -LRB104 16098 AAS 29398 a

1    enforcement of timelines;
2        (5) benefits and challenges associated with group 
3    studies and cost sharing;
4        (6) minimum requirements for application to the 
5    interconnection process and throughout the interconnection 
6    process to avoid queue clogging behavior;
7        (7) the process and customer service for 
8    interconnecting customers adopting distributed energy 
9    resources, including energy storage;
10        (8) options for metering distributed energy resources, 
11    including energy storage;
12        (9) interconnection of new technologies, including 
13    smart inverters and energy storage;
14        (10) collection, examination, and sharing of data on 
15    Level 1 interconnection costs, including cost and type of 
16    upgrades required for interconnection, and the use of this 
17    data to inform the final standardized cost of Level 1 
18    interconnection;
19        (11) determination of a single standardized cost for 
20    Level 1 interconnections, which shall not exceed $200; and
21        (12) such other technical, policy, and tariff issues 
22    related to and affecting interconnection performance and 
23    customer service as determined by the Interconnection 
24    Working Group.
25    (c) The Commission may create subcommittees of the 
26Interconnection Working Group to focus on specific issues of 
 
 
10400SB0025ham004- 890 -LRB104 16098 AAS 29398 a

1importance, as appropriate.
2    (d) The Interconnection Working Group shall report to the 
3Commission on recommended improvements to interconnection 
4rules, tariffs, and policies as determined by the 
5Interconnection Working Group at least every year. A report 
6shall include consensus recommendations of the Interconnection 
7Working Group and, if applicable, additional recommendations 
8for which consensus was not reached. Non-consensus shall not 
9be a basis for excluding recommendations that are majority or 
10minority recommendations. The Commission shall use the report 
11from the Interconnection Working Group to determine whether 
12processes should be commenced to formally codify or implement 
13the recommendations. The Interconnection Working Group shall 
14provide the reports under this subsection (d) to the 
15Commission on at least the following topics in the order 
16listed below within a reasonable time, but no later than 12 
17months, after the effective date of this amendatory Act of the 
18104th General Assembly: (A) a mechanism for good cause 
19extensions to construction timelines as long as the 
20interconnection customer reasonably demonstrates progress; (B) 
21a mechanism for all electric utilities to accept cash, letters 
22of credit, or bonds for any deposits required under the 
23interconnection agreement; (C) cost sharing for distribution 
24system upgrades and interconnection facilities for multiple 
25interconnection customers attempting to interconnect on the 
26same feeder or substation; (D) requirements that 
 
 
10400SB0025ham004- 891 -LRB104 16098 AAS 29398 a

1interconnection studies process without delay based on queue 
2position or status of applications ahead in the queue, and 
3associated requirements for disclosure of contingent upgrades; 
4(E) provisions allowing for queue reservation for the 
5interconnection of projects installed on public school land to 
6accommodate timing constraints of school board approval and 
7budgeting; and (F) if feasible within the time allotted for 
8the initial report, parameters for utility interconnection 
9studies of energy storage systems not paired with distributed 
10generation that are based on the proposed operational profile 
11of the energy storage systems.
12    (d-5) Within 12 months after the report directed by 
13subsection (d) has been submitted, the Working Group shall 
14report to the Commission on the following: (A) mandatory 
15disclosures on the hosting capacity map and studies for 
16contingent upgrades including timelines for notice of 
17responsibility and payment; (B) a framework for concurrent 
18study on multiple feeders for a distributed energy resource; 
19and (C) if not provided in the initial report required under 
20subsection (d), parameters for utility interconnection studies 
21of energy storage systems not paired with distributed 
22generation that are based on the proposed operational profile 
23of the energy storage systems.
24    (d-10) Within 12 months after the report directed by 
25subsection (d-5) has been submitted, the Working Group shall 
26report to the Commission on the following: (A) dynamic hosting 
 
 
10400SB0025ham004- 892 -LRB104 16098 AAS 29398 a

1capacity maps; (B) standards for public queue and hosting 
2capacity map information regarding individual projects in 
3queue, including (i) distributed generation nameplate 
4capacity, (ii) paired or stand-alone energy storage system 
5nameplate capacity, (iii) detailed estimated upgrade costs, 
6and (iv) systems that have completed upgrades and withdrawn 
7projects; and (C) timelines for refund of deposits if the 
8interconnection agreement is terminated. Within the same time 
9period, utilities shall publish all final interconnection 
10agreements, facilities studies, and system impact studies.
11    (d-15) Within 12 months after the report directed by 
12subsection (d-10) has been submitted, the Working Group shall 
13report to the Commission on the following: (A) level of detail 
14of costs in system impact and facilities studies and level 2 
15studies; and (B) a cap on charges to the interconnection 
16customer based on a percentage of the non-binding cost 
17estimate in the facilities study, system impact study, or 
18level 2 study.
19    (e) In collaboration with the General Counsel of the 
20Commission, the Office of Retail Market Development shall 
21develop policies and procedures to facilitate employees of the 
22Office in leading the Interconnection Working Group without 
23interference with docketed proceedings. The policies and 
24procedures developed under this subsection (e) shall be 
25designed to allow the Interconnection Working Group to work 
26without interruption.    
 
 
 
10400SB0025ham004- 893 -LRB104 16098 AAS 29398 a

1    (220 ILCS 5/20-145 new)
2    Sec. 20-145. Interconnection Monitor.
3    (a) The Office of Retail Market Development may employ, 
4designate, or otherwise retain the services of an Ombudsperson 
5who, in addition to the roles described in this Act, is 
6responsible for overseeing electric utility compliance with 
7the standards established by this Section and other regulatory 
8or statutory obligations regarding interconnections.
9    (b) The Ombudsperson may from time to time request, and 
10each electric utility shall timely provide records and 
11information to carry out his or her duties under this Section.
12    (c) The Office shall monitor interconnection between 
13electric utilities and applicants for interconnection and 
14interconnection customers. The Office may request, and 
15electric utilities shall promptly provide, information and 
16records related to pending, successful, and terminated 
17interconnections.
18    (d) The Office may require electric utilities to provide a 
19detailed breakdown of the non-binding costs of operation and 
20an estimate that transparently itemizes operational costs, 
21including equipment by type or model, labor, operation and 
22maintenance, engineering and design, permitting, easements and 
23rights-of-way, direct overhead, and indirect overhead.
24    (e) The Office may establish an informal interconnection 
25dispute resolution process that may supersede 83 Ill. Adm. 
 
 
10400SB0025ham004- 894 -LRB104 16098 AAS 29398 a

1Code 466.130, 83 Ill. Adm. Code 467.80, and interconnection 
2agreements to the extent described in this subsection (e). 
3Following the informal process described in this Section, 
4including any extensions agreed upon by the parties, an 
5electric utility, an interconnection customer, or an 
6interconnection applicant may submit the interconnection 
7dispute to the Ombudsperson, or his or her designee. The 
8Ombudsperson, or his or her designee, shall provide a 
9recommended resolution of such dispute within 30 days after 
10the Ombudsperson determines that full information from all 
11parties to the dispute has been received. The electric 
12utility, the interconnection customer, the interconnection 
13applicant, or any other party authorized to initiate dispute 
14resolution under the Commission's rules authorized by this Act 
15may include the Ombudsperson's recommendation in any formal 
16complaint before the Commission.
17    (f) The Office is encouraged to include at least one 
18employee, at the Bureau Chief's discretion, with a background 
19in engineering of renewable resources and distribution 
20interconnections.    
 
21    (220 ILCS 5/Art. XXIII heading new)
22
ARTICLE XXIII.  SITING OF QUALIFIED ENERGY FACILITIES

 
23    (220 ILCS 5/23-105 new)
24    Sec. 23-105. Findings. The General Assembly finds that the 
 
 
10400SB0025ham004- 895 -LRB104 16098 AAS 29398 a

1timely siting and development of commercial wind energy 
2facilities, commercial solar energy facilities and energy 
3storage system facilities is critical to the State's energy 
4security and that it is the policy of the State that:    
5        (1) the General Assembly has adopted state-wide county 
6    siting regulations to establish uniform standards for 
7    commercial wind energy facilities, commercial solar energy 
8    facilities, and energy storage system facilities 
9    throughout this State;
10        (2) a consistent dispute resolution process, with 
11    respect to the siting and development of commercial wind 
12    energy facilities, commercial solar energy facilities and 
13    energy storage system facilities is necessary to provide 
14    fair and expeditious decisions on siting disputes to 
15    parties affected by the development and siting of a 
16    renewable energy project;
17        (3) empowering the Commission to resolve siting 
18    disputes and issue siting certificates would allow parties 
19    to avoid time-consuming and costly litigation and would 
20    provide consistency and certainty to the renewable energy 
21    siting and development process in the State; and
22        (4) the Commission has the relevant expertise to 
23    establish and govern a renewable energy siting certificate 
24    issuance and dispute resolution process.
 
25    (220 ILCS 5/23-110 new)
 
 
10400SB0025ham004- 896 -LRB104 16098 AAS 29398 a

1    Sec. 23-110. Definitions. In this Article:
2    "Applicable State siting law" means Section 5-12020 of the 
3Counties Code for commercial wind energy facilities and 
4commercial solar energy facilities and means Section 5-12024 
5of the Counties Code for energy storage system facilities    
6    "Commercial solar energy facility" has the meaning given 
7to that term in subsection (a) of Section 5-12020 of the 
8Counties Code. "Commercial solar energy facility" includes 
9supporting facilities, as defined in subsection (a) of Section 
105-12020 of the Counties Code.
11    "Commercial wind energy facility" has the meaning given to 
12that term in subsection (a) of Section 5-12020 of the Counties 
13Code. "Commercial wind energy facility" includes supporting 
14facilities, as defined in subsection (a) of Section 5-12020 of 
15the Counties Code.    
16    "Energy storage system facility" has the meaning given to 
17that term in Section 5-12024 of the Counties Code. "Energy 
18storage system facility" includes supporting facilities, as 
19defined in subsection (a) of Section 5-12024 of the Counties 
20Code.    
21    "Facility owner" means the owner of or an applicant for a 
22qualified energy facility.    
23    "Qualified energy facility" means any one or more of the 
24following that has a nameplate capacity of 50 megawatts or 
25greater and is located in an unincorporated area not within 
26the zoning jurisdiction of an incorporated municipality: a 
 
 
10400SB0025ham004- 897 -LRB104 16098 AAS 29398 a

1commercial wind energy facility, a commercial solar energy 
2facility, or an energy storage system facility.    
3    "Respondent" means the county, municipality, township, 
4road district, or other unit of local government whose action 
5or inaction is the subject of the dispute.    
 
6    (220 ILCS 5/23-115 new)
7    Sec. 23-115. Resolution of disputes between facility 
8owners and units of local government related to the siting of 
9qualified energy facilities.    
10    (a) The expedited procedures in this Section shall be used 
11to enforce the provisions of the applicable State siting law.
12    (b) No petition may be filed under this Section until the 
13facility owner that intends to file the petition has first 
14notified the respondent of the alleged violation of the 
15applicable State siting law and offered the respondent 7 days 
16to correct or take substantial steps to begin and diligently 
17pursue curing the alleged violation. Provision of notice and 
18the opportunity to correct the situation creates a rebuttable 
19presumption of knowledge under this Section. After the filing 
20of a petition under this Section, the parties may agree to 
21follow the mediation process under Section 10-101.1 of this 
22Act. The time periods specified in subdivision (c)(7) of this 
23Section shall be tolled during the time spent in mediation 
24under Section 10-101.1.
25    (c) A facility owner may file a petition with the 
 
 
10400SB0025ham004- 898 -LRB104 16098 AAS 29398 a

1Commission alleging a violation of the applicable State siting 
2law in accordance with this subsection. The following 
3procedures shall govern the dispute resolution process:
4        (1) The petition shall be filed with the Chief Clerk 
5    of the Commission and shall be served in hand upon the 
6    respondent, the executive director, and the general 
7    counsel of the Commission at the time of the filing.
8        (2) A petition filed under this subsection shall 
9    include a statement that the requirements of subsection 
10    (b) have been fulfilled and that the respondent did not 
11    correct the situation as requested.
12        (3) Reasonable discovery specific to the issue of the 
13    petition may commence upon filing of the petition.
14        (4) An answer and any other responsive pleading to the 
15    petition shall be filed with the Commission and served at 
16    the same time upon the complainant, the executive 
17    director, and the general counsel of the Commission within 
18    7 days after the date on which the petition is filed.
19        (5) If the answer or responsive pleading raises the 
20    issue that the petition violates subsection (f) of this 
21    Section, the complainant may file a reply to such 
22    allegation within 3 days after actual service of such 
23    answer or responsive pleading. Within 4 days after the 
24    time for filing a reply has expired, the administrative 
25    law judge shall either issue a written decision dismissing 
26    the petition as frivolous in violation of subsection (f) 
 
 
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1    of this Section including the reasons for such disposition 
2    or shall issue an order directing that the petition shall 
3    proceed.
4        (6) A pre-hearing conference shall be held within 14 
5    days after the date on which the petition is filed.
6        (7) The hearing shall commence within 45 days of the 
7    date on which the petition is filed and shall be conducted 
8    by an administrative law judge. Parties and the Commission 
9    staff shall be entitled to present evidence and legal 
10    argument in oral or written form as deemed appropriate by 
11    the administrative law judge. The administrative law judge 
12    shall issue a proposed order within 90 days after the date 
13    on which the petition is filed. The proposed order shall 
14    include reasons for the disposition of the petition and, 
15    if a violation of the applicable State siting law is 
16    found, directions and a deadline for correction of the 
17    violation.
18        (8) Any party may file a petition requesting the 
19    Commission to review the proposed order of the 
20    administrative law judge or arbitrator within 5 days after 
21    the proposed order is issued and file exceptions to the 
22    proposed order. Any party may file a response to a 
23    petition for review within 3 business days after actual 
24    service of the petition. After the time for filing of the 
25    petition for review, but no later than 60 days after the 
26    proposed order of the administrative law judge, the 
 
 
10400SB0025ham004- 900 -LRB104 16098 AAS 29398 a

1    Commission shall decide to adopt the proposed order of the 
2    administrative law judge or shall issue its own final 
3    order.
4    (d) In resolving disputes filed under this Section, the 
5administrative law judge and the Commission shall make 
6determinations based on the requirements and intent of the 
7applicable State siting law.
8    (e) In resolving disputes under this Section, the 
9Commission shall have authority to issue a siting certificate 
10for a qualified energy facility if the Commission determines 
11that:
12        (1) the respondent denied the qualified energy 
13    facility a siting certificate; and
14        (2) the qualified energy facility is in compliance 
15    with the applicable State siting laws for a qualified 
16    energy facility.
17    For the purposes of this Section, a commercial wind energy 
18facility and commercial solar energy facility shall be in 
19compliance with Section 5-12020 of the Counties Code and an 
20energy storage system shall be in compliance with Section 
215-12024 of the Counties Code. If the Commission determines 
22that there is substantial harm to the facility owner, the 
23Commission may, notwithstanding any other provision of this 
24Act, seek temporary, preliminary, or permanent injunctive 
25relief from a court of competent jurisdiction either before or 
26after the hearing.
 
 
10400SB0025ham004- 901 -LRB104 16098 AAS 29398 a

1    (f) A party shall not bring or defend a proceeding brought 
2under this Section or assert or controvert an issue in a 
3proceeding brought under this Section, unless there is a 
4non-frivolous basis for doing so. By presenting a pleading, 
5written motion, or other paper in petition or defense of the 
6actions or inaction of a party under this Section, a party is 
7certifying to the Commission that to the best of that party's 
8knowledge, information, and belief, formed after a reasonable 
9inquiry of the subject matter of the petition or defense, that 
10the petition or defense is well grounded in law and fact, and 
11under the circumstances:
12        (1) it is not being presented to harass the other 
13    party, cause unnecessary delay, or create needless 
14    increases in the cost of litigation; and
15        (2) the allegations and other factual contentions have 
16    evidentiary support or, if specifically so identified, are 
17    likely to have evidentiary support after reasonable 
18    opportunity for further investigation or discovery as 
19    defined herein.
20    (g) If, after notice and a reasonable opportunity to 
21respond, the Commission determines that subsection (f) has 
22been violated, the Commission shall impose appropriate 
23sanctions upon the party or parties that have violated 
24subsection (i) or are responsible for the violation.
25    (h) An appeal of a Commission order made pursuant to this 
26Section shall not effectuate a stay of the order unless a court 
 
 
10400SB0025ham004- 902 -LRB104 16098 AAS 29398 a

1of competent jurisdiction specifically finds that the party 
2seeking the stay will likely succeed on the merits, that the 
3party will suffer irreparable harm without the stay, and that 
4the stay is in the public interest.
5    (i) The Commission shall assess the parties under this 
6subsection for all of the Commission's costs of investigation 
7and conduct of the proceedings brought under this Section 
8including, but not limited to, the prorated salaries of staff, 
9attorneys, administrative law judges, and support personnel 
10and including any travel and per diem, directly attributable 
11to the petition brought pursuant to this Section, but 
12excluding those costs provided for in subsection (g), dividing 
13the costs according to the resolution of the petition brought 
14under this Section. All assessments made under this subsection 
15shall be paid into the Public Utility Fund within 60 days after 
16receiving notice of the assessments from the Commission. 
17Interest at the statutory rate shall accrue after the 
18expiration of the 60-day period. The Commission is authorized 
19to apply to a court of competent jurisdiction for an order 
20requiring payment.
 
21    (220 ILCS 5/23-120 new)
22    Sec. 23-120. Effect of siting certificate. A siting 
23approval certificate authorizes the facility owner receiving 
24the certificate to construct, maintain, and decommission the 
25qualified energy facility.
 
 
 
10400SB0025ham004- 903 -LRB104 16098 AAS 29398 a

1    (220 ILCS 5/23-125 new)
2    Sec. 23-125. Rulemaking. The Commission may adopt rules to 
3implement the requirements of this Article.
 
4    Section 90-40. The Electric Transmission Systems 
5Construction Standards Act is amended by changing Sections 5 
6and 15 as follows:
 
7    (220 ILCS 32/5)
8    Sec. 5. Definitions. For the purposes of this Act:
9    "Commission" means the Illinois Commerce Commission. 
10    "Construction contractor" means any nonutility entity 
11responsible for the construction, installation, maintenance, 
12or repair of electric transmission systems subject to this 
13Act.
14    "Electric transmission systems" means an electrical 
15transmission system designed and constructed with the 
16capability of being safely and reliably energized at 69 
17kilovolts or more, including transmission lines, transmission 
18towers, conductors, insulators, foundations, grounding 
19systems, access roads, and all associated transmission 
20facilities, including transmission substations. "Electric 
21transmission systems" does not include projects located on the 
22electric generating facility's side of the facility's point of 
23interconnection or facilities not functionally classified as 
 
 
10400SB0025ham004- 904 -LRB104 16098 AAS 29398 a

1transmission systems, regardless of voltage.
2    "OSHA" means Occupational Safety and Health 
3Administration.
4    "Utility" means an entity that is a public utility, as 
5defined in Section 3-105 of the Public Utilities Act, and that 
6serves residential customers. has the meaning given to that 
7term in Section 3-105 of the Public Utilities Act.
8(Source: P.A. 103-1066, eff. 2-20-25.)
 
9    (220 ILCS 32/15)
10    Sec. 15. Requirements for construction contractors.
11    (a) Prevailing wage compliance. All utilities and    
12construction contractors responsible for the construction, 
13installation, maintenance, or repair of electric transmission 
14systems shall pay employees performing the construction, 
15installation, maintenance, or repair work of such systems 
16wages and benefits consistent with the Prevailing Wage Act.
17    (b) Training and competence requirement. To ensure safety 
18and reliability in the construction, installation, 
19maintenance, and repair of electric transmission systems, each 
20electric utility and construction contractor must demonstrate 
21the competence of their employees who are performing the work 
22of construction, installation, maintenance, or repair of 
23electric transmission systems, which shall be consistent with 
24the standards required by Illinois utilities as of January 1, 
252007, or greater. Competence must include, at a minimum: (1) 
 
 
10400SB0025ham004- 905 -LRB104 16098 AAS 29398 a

1completion, or active participation with ultimate completion, 
2in an accredited or recognized apprenticeship program for the 
3relevant craft, trade, or skill; or (2) a minimum of 2 years of 
4direct employment in the specific work function. 
5    The Commission shall oversee compliance to ensure 
6employees meet these standards.
7    (c) Safety training. All employees engaged in the 
8construction, installation, maintenance, or repair of electric 
9transmission systems must successfully complete OSHA-certified 
10safety training required for their specific roles on the 
11project site.
12    (d) Diversity Plan.
13        (1) All construction contractors engaged in the 
14    construction, installation, maintenance, or repair of 
15    electric transmission systems shall develop a Diversity 
16    Plan that sets forth:
17            (A) the goals for apprenticeship hours to be 
18        performed by minorities and women;
19            (B) the goals for total hours to be performed by 
20        underrepresented minorities and women; and
21            (C) spending for women-owned, minority-owned, 
22        veteran-owned, and small business enterprises in the 
23        previous calendar year.
24        (2) These goals shall be expressed as a percentage of 
25    the total work performed by the construction contractor 
26    submitting the plan and the actual spending for all 
 
 
10400SB0025ham004- 906 -LRB104 16098 AAS 29398 a

1    women-owned, minority-owned, veteran-owned, and small 
2    business enterprises shall also be expressed as a 
3    percentage of the total work performed by the construction 
4    contractor submitting the Diversity Plan.
5        (3) For purposes of the Diversity Plan, minorities and 
6    women shall have the same definition as defined in the 
7    Business Enterprise for Minorities, Women, and Persons 
8    with Disabilities Act.
9        (4) The construction contractor shall submit the 
10    Diversity Plan to the Commission.
11(Source: P.A. 103-1066, eff. 2-20-25.)
 
12    Section 90-45. The Environmental Protection Act is amended 
13by changing Sections 9.15, 25, and 39 as follows:
 
14    (415 ILCS 5/9.15)
15    Sec. 9.15. Greenhouse gases.
16    (a) An air pollution construction permit shall not be 
17required due to emissions of greenhouse gases if the 
18equipment, site, or source is not subject to regulation, as 
19defined by 40 CFR 52.21, as now or hereafter amended, for 
20greenhouse gases or is otherwise not addressed in this Section 
21or by the Board in regulations for greenhouse gases. These 
22exemptions do not relieve an owner or operator from the 
23obligation to comply with other applicable rules or 
24regulations.
 
 
10400SB0025ham004- 907 -LRB104 16098 AAS 29398 a

1    (b) An air pollution operating permit shall not be 
2required due to emissions of greenhouse gases if the 
3equipment, site, or source is not subject to regulation, as 
4defined by Section 39.5 of this Act, for greenhouse gases or is 
5otherwise not addressed in this Section or by the Board in 
6regulations for greenhouse gases. These exemptions do not 
7relieve an owner or operator from the obligation to comply 
8with other applicable rules or regulations.
9    (c) (Blank). 
10    (d) (Blank).
11    (e) (Blank). 
12    (f) As used in this Section:
13    "Carbon dioxide emission" means the plant annual CO2 total 
14output emission as measured by the United States Environmental 
15Protection Agency in its Emissions & Generation Resource 
16Integrated Database (eGrid), or its successor. 
17    "Carbon dioxide equivalent emissions" or "CO2e" means the 
18sum total of the mass amount of emissions in tons per year, 
19calculated by multiplying the mass amount of each of the 6 
20greenhouse gases specified in Section 3.207, in tons per year, 
21by its associated global warming potential as set forth in 40 
22CFR 98, subpart A, table A-1 or its successor, and then adding 
23them all together.
24    "Cogeneration" or "combined heat and power" refers to any 
25system that, either simultaneously or sequentially, produces 
26electricity and useful thermal energy from a single fuel 
 
 
10400SB0025ham004- 908 -LRB104 16098 AAS 29398 a

1source.
2    "Copollutants" refers to the 6 criteria pollutants that 
3have been identified by the United States Environmental 
4Protection Agency pursuant to the Clean Air Act.
5    "Electric generating unit" or "EGU" means a fossil 
6fuel-fired stationary boiler, combustion turbine, or combined 
7cycle system that serves a generator that has a nameplate 
8capacity greater than 25 MWe and produces electricity for 
9sale.
10    "Environmental justice community" means the definition of 
11that term based on existing methodologies and findings, used 
12and as may be updated by the Illinois Power Agency and its 
13program administrator in the Illinois Solar for All Program.
14    "Equity investment eligible community" or "eligible 
15community" means the geographic areas throughout Illinois that 
16would most benefit from equitable investments by the State 
17designed to combat discrimination and foster sustainable 
18economic growth. Specifically, eligible community means the 
19following areas:
20        (1) areas where residents have been historically 
21    excluded from economic opportunities, including 
22    opportunities in the energy sector, as defined as R3 areas 
23    pursuant to Section 10-40 of the Cannabis Regulation and 
24    Tax Act; and
25        (2) areas where residents have been historically 
26    subject to disproportionate burdens of pollution, 
 
 
10400SB0025ham004- 909 -LRB104 16098 AAS 29398 a

1    including pollution from the energy sector, as established 
2    by environmental justice communities as defined by the 
3    Illinois Power Agency pursuant to the Illinois Power 
4    Agency Act, excluding any racial or ethnic indicators.
5    "Equity investment eligible person" or "eligible person" 
6means the persons who would most benefit from equitable 
7investments by the State designed to combat discrimination and 
8foster sustainable economic growth. Specifically, eligible 
9person means the following people:
10        (1) persons whose primary residence is in an equity 
11    investment eligible community;
12        (2) persons whose primary residence is in a 
13    municipality, or a county with a population under 100,000, 
14    where the closure of an electric generating unit or mine 
15    has been publicly announced or the electric generating 
16    unit or mine is in the process of closing or closed within 
17    the last 5 years;
18        (3) persons who are graduates of or currently enrolled 
19    in the foster care system; or
20        (4) persons who were formerly incarcerated.
21    "Existing emissions" means: 
22        (1) for CO2e, the total average tons-per-year of CO2e 
23    emitted by the EGU or large GHG-emitting unit either in 
24    the years 2018 through 2020 or, if the unit was not yet in 
25    operation by January 1, 2018, in the first 3 full years of 
26    that unit's operation; and
 
 
10400SB0025ham004- 910 -LRB104 16098 AAS 29398 a

1        (2) for any copollutant, the total average 
2    tons-per-year of that copollutant emitted by the EGU or 
3    large GHG-emitting unit either in the years 2018 through 
4    2020 or, if the unit was not yet in operation by January 1, 
5    2018, in the first 3 full years of that unit's operation. 
6    "Green hydrogen" means a power plant technology in which 
7an EGU creates electric power exclusively from electrolytic 
8hydrogen, in a manner that produces zero carbon and 
9copollutant emissions, using hydrogen fuel that is 
10electrolyzed using a 100% renewable zero carbon emission 
11energy source.
12    "Large greenhouse gas-emitting unit" or "large 
13GHG-emitting unit" means a unit that is an electric generating 
14unit or other fossil fuel-fired unit that itself has a 
15nameplate capacity or serves a generator that has a nameplate 
16capacity greater than 25 MWe and that produces electricity, 
17including, but not limited to, coal-fired, coal-derived, 
18oil-fired, natural gas-fired, and cogeneration units.
19    "NOx emission rate" means the plant annual NOx total output 
20emission rate as measured by the United States Environmental 
21Protection Agency in its Emissions & Generation Resource 
22Integrated Database (eGrid), or its successor, in the most 
23recent year for which data is available.
24    "Public greenhouse gas-emitting units" or "public 
25GHG-emitting unit" means large greenhouse gas-emitting units, 
26including EGUs, that are wholly owned, directly or indirectly, 
 
 
10400SB0025ham004- 911 -LRB104 16098 AAS 29398 a

1by one or more municipalities, municipal corporations, joint 
2municipal electric power agencies, electric cooperatives, or 
3other governmental or nonprofit entities, whether organized 
4and created under the laws of Illinois or another state.
5    "SO2 emission rate" means the "plant annual SO2 total 
6output emission rate" as measured by the United States 
7Environmental Protection Agency in its Emissions & Generation 
8Resource Integrated Database (eGrid), or its successor, in the 
9most recent year for which data is available.
10    (g) All EGUs and large greenhouse gas-emitting units that 
11use coal or oil as a fuel and are not public GHG-emitting units 
12shall permanently reduce all CO2e and copollutant emissions to 
13zero no later than January 1, 2030.
14    (h) All EGUs and large greenhouse gas-emitting units that 
15use coal as a fuel and are public GHG-emitting units shall 
16permanently reduce CO2e emissions to zero no later than 
17December 31, 2045. Any source or plant with such units must 
18also reduce their CO2e emissions by 45% from existing 
19emissions by no later than January 1, 2035. If the emissions 
20reduction requirement is not achieved by December 31, 2035, 
21the plant shall retire one or more units or otherwise reduce 
22its CO2e emissions by 45% from existing emissions by June 30, 
232038.
24    (i) All EGUs and large greenhouse gas-emitting units that 
25use gas as a fuel and are not public GHG-emitting units shall 
26permanently reduce all CO2e and copollutant emissions to zero, 
 
 
10400SB0025ham004- 912 -LRB104 16098 AAS 29398 a

1including through unit retirement or the use of 100% green 
2hydrogen or other similar technology that is commercially 
3proven to achieve zero carbon emissions, according to the 
4following:
5        (1) No later than January 1, 2030: all EGUs and large 
6    greenhouse gas-emitting units that have a NOx emissions 
7    rate of greater than 0.12 lbs/MWh or a SO2 emission rate of 
8    greater than 0.006 lb/MWh, and are located in or within 3 
9    miles of an environmental justice community designated as 
10    of January 1, 2021 or an equity investment eligible 
11    community.
12        (2) No later than January 1, 2040: all EGUs and large 
13    greenhouse gas-emitting units that have a NOx emission 
14    rate of greater than 0.12 lbs/MWh or a SO2 emission rate 
15    greater than 0.006 lb/MWh, and are not located in or 
16    within 3 miles of an environmental justice community 
17    designated as of January 1, 2021 or an equity investment 
18    eligible community. After January 1, 2035, each such EGU 
19    and large greenhouse gas-emitting unit shall reduce its 
20    CO2e emissions by at least 50% from its existing emissions 
21    for CO2e, and shall be limited in operation to, on average, 
22    6 hours or less per day, measured over a calendar year, and 
23    shall not run for more than 24 consecutive hours except in 
24    emergency conditions, as designated by a Regional 
25    Transmission Organization or Independent System Operator.
26        (3) No later than January 1, 2035: all EGUs and large 
 
 
10400SB0025ham004- 913 -LRB104 16098 AAS 29398 a

1    greenhouse gas-emitting units that began operation prior 
2    to the effective date of this amendatory Act of the 102nd 
3    General Assembly and have a NOx emission rate of less than 
4    or equal to 0.12 lb/MWh and a SO2 emission rate less than 
5    or equal to 0.006 lb/MWh, and are located in or within 3 
6    miles of an environmental justice community designated as 
7    of January 1, 2021 or an equity investment eligible 
8    community. Each such EGU and large greenhouse gas-emitting 
9    unit shall reduce its CO2e emissions by at least 50% from 
10    its existing emissions for CO2e no later than January 1, 
11    2030.
12        (4) No later than January 1, 2040: All remaining EGUs 
13    and large greenhouse gas-emitting units that have a heat 
14    rate greater than or equal to 7000 BTU/kWh. Each such EGU 
15    and Large greenhouse gas-emitting unit shall reduce its 
16    CO2e emissions by at least 50% from its existing emissions 
17    for CO2e no later than January 1, 2035.
18        (5) No later than January 1, 2045: all remaining EGUs 
19    and large greenhouse gas-emitting units. 
20    (j) All EGUs and large greenhouse gas-emitting units that 
21use gas as a fuel and are public GHG-emitting units shall 
22permanently reduce all CO2e and copollutant emissions to zero, 
23including through unit retirement or the use of 100% green 
24hydrogen or other similar technology that is commercially 
25proven to achieve zero carbon emissions by January 1, 2045.
26    (k) All EGUs and large greenhouse gas-emitting units that 
 
 
10400SB0025ham004- 914 -LRB104 16098 AAS 29398 a

1utilize combined heat and power or cogeneration technology 
2shall permanently reduce all CO2e and copollutant emissions to 
3zero, including through unit retirement or the use of 100% 
4green hydrogen or other similar technology that is 
5commercially proven to achieve zero carbon emissions by 
6January 1, 2045.
7    (k-5) No EGU or large greenhouse gas-emitting unit that 
8uses gas as a fuel and is not a public GHG-emitting unit may 
9emit, in any 12-month period, CO2e or copollutants in excess of 
10that unit's existing emissions for those pollutants. 
11    (l) Notwithstanding subsections (g) through (k-5), large 
12GHG-emitting units including EGUs may temporarily continue 
13emitting CO2e and copollutants after any applicable deadline 
14specified in any of subsections (g) through (k-5) if it has 
15been determined, as described in paragraphs (1) and (2) of 
16this subsection, that ongoing operation of the EGU is 
17necessary to maintain power grid supply and reliability or 
18ongoing operation of large GHG-emitting unit that is not an 
19EGU is necessary to serve as an emergency backup to 
20operations. Up to and including the occurrence of an emission 
21reduction deadline under subsection (i), all EGUs and large 
22GHG-emitting units must comply with the following terms:
23        (1) if an EGU or large GHG-emitting unit that is a 
24    participant in a regional transmission organization 
25    intends to retire, it must submit documentation to the 
26    appropriate regional transmission organization by the 
 
 
10400SB0025ham004- 915 -LRB104 16098 AAS 29398 a

1    appropriate deadline that meets all applicable regulatory 
2    requirements necessary to obtain approval to permanently 
3    cease operating the large GHG-emitting unit;
4        (2) if any EGU or large GHG-emitting unit that is a 
5    participant in a regional transmission organization 
6    receives notice that the regional transmission 
7    organization has determined that continued operation of 
8    the unit is required, the unit may continue operating 
9    until the issue identified by the regional transmission 
10    organization is resolved. The owner or operator of the 
11    unit must cooperate with the regional transmission 
12    organization in resolving the issue and must reduce its 
13    emissions to zero, consistent with the requirements under 
14    subsection (g), (h), (i), (j), (k), or (k-5), as 
15    applicable, as soon as practicable when the issue 
16    identified by the regional transmission organization is 
17    resolved; and
18        (3) any large GHG-emitting unit that is not a 
19    participant in a regional transmission organization shall 
20    be allowed to continue emitting CO2e and copollutants 
21    after the zero-emission date specified in subsection (g), 
22    (h), (i), (j), (k), or (k-5), as applicable, in the 
23    capacity of an emergency backup unit if approved by the 
24    Illinois Commerce Commission.
25    (m) No variance, adjusted standard, or other regulatory 
26relief otherwise available in this Act may be granted to the 
 
 
10400SB0025ham004- 916 -LRB104 16098 AAS 29398 a

1emissions reduction and elimination obligations in this 
2Section.
3    (n) By June 30 of each year, beginning in 2025, the Agency 
4shall prepare and publish on its website a report setting 
5forth the actual greenhouse gas emissions from individual 
6units and the aggregate statewide emissions from all units for 
7the prior year.
8    (o) The Every 5 years beginning in 2025, the Environmental 
9Protection Agency, Illinois Power Agency, and Illinois 
10Commerce Commission shall jointly prepare, and release 
11publicly, a report to the General Assembly that examines the 
12State's current progress toward its renewable energy resource 
13development goals, the status of CO2e and copollutant 
14emissions reductions, the current status and progress toward 
15developing and implementing green hydrogen technologies, the 
16current and projected status of electric resource adequacy and 
17reliability throughout the State for the period beginning 5 
18years ahead, and proposed solutions for any findings. The 
19Environmental Protection Agency, Illinois Power Agency, and 
20Illinois Commerce Commission shall consult PJM 
21Interconnection, LLC and Midcontinent Independent System 
22Operator, Inc., or their respective successor organizations 
23regarding forecasted resource adequacy and reliability needs, 
24anticipated new generation interconnection, new transmission 
25development or upgrades, and any announced large GHG-emitting 
26unit closure dates and include this information in the report. 
 
 
10400SB0025ham004- 917 -LRB104 16098 AAS 29398 a

1The report shall be released publicly by no later than 
2December 15 of the year it is prepared. If the Environmental 
3Protection Agency, Illinois Power Agency, and Illinois 
4Commerce Commission jointly conclude in the report that the 
5data from the regional grid operators, the pace of renewable 
6energy development, the pace of development of energy storage 
7and demand response utilization, transmission capacity, and 
8the CO2e and copollutant emissions reductions required by 
9subsection (i) or (k-5) reasonably demonstrate that a resource 
10adequacy shortfall will occur, including whether there will be 
11sufficient in-state capacity to meet the zonal requirements of 
12MISO Zone 4 or the PJM ComEd Zone, per the requirements of the 
13regional transmission organizations, or that the regional 
14transmission operators determine that a reliability violation 
15will occur during the time frame the study is evaluating, then 
16the Illinois Power Agency, in conjunction with the 
17Environmental Protection Agency shall develop a plan to reduce 
18or delay CO2e and copollutant emissions reductions 
19requirements only to the extent and for the duration necessary 
20to meet the resource adequacy and reliability needs of the 
21State, including allowing any plants whose emission reduction 
22deadline has been identified in the plan as creating a 
23reliability concern to continue operating, including operating 
24with reduced emissions or as emergency backup where 
25appropriate. The plan shall also consider the use of renewable 
26energy, energy storage, demand response, transmission 
 
 
10400SB0025ham004- 918 -LRB104 16098 AAS 29398 a

1development, or other strategies to resolve the identified 
2resource adequacy shortfall or reliability violation.
3        (1) In developing the plan, the Environmental 
4    Protection Agency and the Illinois Power Agency shall hold 
5    at least one workshop open to, and accessible at a time and 
6    place convenient to, the public and shall consider any 
7    comments made by stakeholders or the public. Upon 
8    development of the plan, copies of the plan shall be 
9    posted and made publicly available on the Environmental 
10    Protection Agency's, the Illinois Power Agency's, and the 
11    Illinois Commerce Commission's websites. All interested 
12    parties shall have 60 days following the date of posting 
13    to provide comment to the Environmental Protection Agency 
14    and the Illinois Power Agency on the plan. All comments 
15    submitted to the Environmental Protection Agency and the 
16    Illinois Power Agency shall be encouraged to be specific, 
17    supported by data or other detailed analyses, and, if 
18    objecting to all or a portion of the plan, accompanied by 
19    specific alternative wording or proposals. All comments 
20    shall be posted on the Environmental Protection Agency's, 
21    the Illinois Power Agency's, and the Illinois Commerce 
22    Commission's websites. Within 30 days following the end of 
23    the 60-day review period, the Environmental Protection 
24    Agency and the Illinois Power Agency shall revise the plan 
25    as necessary based on the comments received and file its 
26    revised plan with the Illinois Commerce Commission for 
 
 
10400SB0025ham004- 919 -LRB104 16098 AAS 29398 a

1    approval.
2        (2) Within 60 days after the filing of the revised 
3    plan at the Illinois Commerce Commission, any person 
4    objecting to the plan shall file an objection with the 
5    Illinois Commerce Commission. Within 30 days after the 
6    expiration of the comment period, the Illinois Commerce 
7    Commission shall determine whether an evidentiary hearing 
8    is necessary. The Illinois Commerce Commission shall also 
9    host 3 public hearings within 90 days after the plan is 
10    filed. Following the evidentiary and public hearings, the 
11    Illinois Commerce Commission shall enter its order 
12    approving or approving with modifications the reliability 
13    mitigation plan within 180 days.
14        (3) The Illinois Commerce Commission shall only 
15    approve the plan if the Illinois Commerce Commission 
16    determines that it will resolve the resource adequacy or 
17    reliability deficiency identified in the reliability 
18    mitigation plan at the least amount of CO2e and copollutant 
19    emissions, taking into consideration the emissions impacts 
20    on environmental justice communities, and that it will 
21    ensure adequate, reliable, affordable, efficient, and 
22    environmentally sustainable electric service at the lowest 
23    total cost over time, taking into account the impact of 
24    increases in emissions.
25        (4) If the resource adequacy or reliability deficiency 
26    identified in the reliability mitigation plan is resolved 
 
 
10400SB0025ham004- 920 -LRB104 16098 AAS 29398 a

1    or reduced, the Environmental Protection Agency and the 
2    Illinois Power Agency may file an amended plan adjusting 
3    the reduction or delay in CO2e and copollutant emission 
4    reduction requirements identified in the plan. 
5(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
6    (415 ILCS 5/25)  (from Ch. 111 1/2, par. 1025)
7    Sec. 25. The Board, pursuant to the procedures prescribed 
8in Title VII of this Act, may adopt regulations prescribing 
9limitations on noise emissions beyond the boundaries of the 
10property of any person and prescribing requirements and 
11standards for equipment and procedures for monitoring noise 
12and the collection, reporting and retention of data resulting 
13from such monitoring.
14    The Board shall, by regulations under this Section, 
15categorize the types and sources of noise emissions that 
16unreasonably interfere with the enjoyment of life, or with any 
17lawful business, or activity, and shall prescribe for each 
18such category the maximum permissible limits on such noise 
19emissions. The Board shall secure the co-operation of the 
20Department in determining the categories of noise emission and 
21the technological and economic feasibility of such noise level 
22limits.
23    In connection with any commercial solar energy facility or 
24commercial wind energy facility, the fee simple owner of a 
25participating property, participating residence, 
 
 
10400SB0025ham004- 921 -LRB104 16098 AAS 29398 a

1nonparticipating property, nonparticipating residence, or any 
2combination of those properties and residences may enter into 
3a written waiver agreement or other similar instrument 
4pursuant to which the owner agrees to waive the enforcement, 
5either entirely or on a limited basis, of the rules and 
6regulations that are adopted under this Section or Section 24 
7of this Act and that pertain to the facility. Such a waiver 
8shall be recorded in the Office of the Recorder of the county 
9in which the participating property, participating residence, 
10nonparticipating property, or nonparticipating residence is 
11located and, once recorded, shall be binding upon and 
12constructive notice to all current and future owners, 
13residents, lessees, invitees, and users of the property so 
14long as the recorded waiver includes a legal description or 
15location of the affected property and a reference that it 
16waives certain provisions of this Act and their enforcement, 
17as well as certain rules and regulations adopted under this 
18Act and their enforcement. Upon the recording of such a 
19waiver, in addition to the owner, the Board, Agency, or other 
20person shall not be permitted to enforce the rules and 
21regulations adopted under this Section or Section 24, and 
22those rules and regulations shall not be effective, to the 
23extent the rules and regulations for the affected property 
24have been waived under this Section, against the facility that 
25is the subject of the recorded waiver. An owner of any 
26participating residence or nonparticipating residence shall 
 
 
10400SB0025ham004- 922 -LRB104 16098 AAS 29398 a

1disclose the existence of such a waiver to any lessee before 
2entering any new lease for the residence. A seller of any 
3participating property, participating residence, 
4nonparticipating property, nonparticipating residence, or any 
5combination of those properties and residences shall disclose 
6the existence of the waiver before any sale or other transfer 
7of the property. If disclosure of the waiver occurs after the 
8buyer has made an offer to purchase the property, the seller 
9shall disclose the existence of the waiver before accepting 
10the buyer's offer and shall (1) allow the buyer an opportunity 
11to review the disclosure and (2) inform the buyer that the 
12buyer has the right to amend the buyer's offer. As used in this 
13Section, "commercial solar energy facility", "commercial wind 
14energy facility", "nonparticipating property", 
15"nonparticipating residence", "participating property", and 
16"participating residence" have the meanings given in 
17subsection (a) of Section 5-12020 of the Counties Code.    
18    In establishing such limits, the Board, in addition to 
19considering those factors set forth in Section 27 of this Act, 
20shall consider the adverse ecological effects on and 
21interference with the enjoyment of natural, scenic, wilderness 
22or other outdoor recreational areas, parks, and forests 
23occasioned by noise emissions from automotive, mechanical, and 
24other sources and may establish lower permissible noise levels 
25applicable to sources in such outdoor recreational uses.
26    No Board standards for monitoring noise or regulations 
 
 
10400SB0025ham004- 923 -LRB104 16098 AAS 29398 a

1prescribing limitations on noise emissions shall apply to any 
2organized amateur or professional sporting activity except as 
3otherwise provided in this Section. Baseball, football or 
4soccer sporting events played during nighttime hours, by 
5professional athletes, in a city with more than 1,000,000 
6inhabitants, in a stadium at which such nighttime events were 
7not played prior to July 1, 1982, shall be subject to nighttime 
8noise emission regulations promulgated by the Illinois 
9Pollution Control Board; however, the following events shall 
10not be subject to such regulations:
11    (1) baseball World Series games, league championship 
12series games and other playoff games played after the 
13conclusion of the regular season, and baseball All Star games; 
14and
15    (2) sporting events or other events held in a stadium 
16which replaces a stadium not subject to such regulations and 
17constructed within 1500 yards of the original stadium by the 
18Illinois Sports Facilities Authority.
19    For purposes of this Section and Section 24, "beyond the 
20boundaries of his property" or "beyond the boundaries of the 
21property of any person" includes personal property as well as 
22real property.
23(Source: P.A. 89-445, eff. 2-7-96.)
 
24    (415 ILCS 5/39)  (from Ch. 111 1/2, par. 1039)
25    Sec. 39. Issuance of permits; procedures. 
 
 
10400SB0025ham004- 924 -LRB104 16098 AAS 29398 a

1    (a) When the Board has by regulation required a permit for 
2the construction, installation, or operation of any type of 
3facility, equipment, vehicle, vessel, or aircraft, the 
4applicant shall apply to the Agency for such permit and it 
5shall be the duty of the Agency to issue such a permit upon 
6proof by the applicant that the facility, equipment, vehicle, 
7vessel, or aircraft will not cause a violation of this Act or 
8of regulations hereunder. The Agency shall adopt such 
9procedures as are necessary to carry out its duties under this 
10Section. In making its determinations on permit applications 
11under this Section the Agency may consider prior adjudications 
12of noncompliance with this Act by the applicant that involved 
13a release of a contaminant into the environment. In granting 
14permits, the Agency may impose reasonable conditions 
15specifically related to the applicant's past compliance 
16history with this Act as necessary to correct, detect, or 
17prevent noncompliance. The Agency may impose such other 
18conditions as may be necessary to accomplish the purposes of 
19this Act, and as are not inconsistent with the regulations 
20promulgated by the Board hereunder. Except as otherwise 
21provided in this Act, a bond or other security shall not be 
22required as a condition for the issuance of a permit. If the 
23Agency denies any permit under this Section, the Agency shall 
24transmit to the applicant within the time limitations of this 
25Section specific, detailed statements as to the reasons the 
26permit application was denied. Such statements shall include, 
 
 
10400SB0025ham004- 925 -LRB104 16098 AAS 29398 a

1but not be limited to, the following:
2        (i) the Sections of this Act which may be violated if 
3    the permit were granted;
4        (ii) the provision of the regulations, promulgated 
5    under this Act, which may be violated if the permit were 
6    granted;
7        (iii) the specific type of information, if any, which 
8    the Agency deems the applicant did not provide the Agency; 
9    and
10        (iv) a statement of specific reasons why the Act and 
11    the regulations might not be met if the permit were 
12    granted.
13    If there is no final action by the Agency within 90 days 
14after the filing of the application for permit, the applicant 
15may deem the permit issued; except that this time period shall 
16be extended to 180 days when (1) notice and opportunity for 
17public hearing are required by State or federal law or 
18regulation, (2) the application which was filed is for any 
19permit to develop a landfill subject to issuance pursuant to 
20this subsection, or (3) the application that was filed is for a 
21MSWLF unit required to issue public notice under subsection 
22(p) of Section 39. The 90-day and 180-day time periods for the 
23Agency to take final action do not apply to NPDES permit 
24applications under subsection (b) of this Section, to RCRA 
25permit applications under subsection (d) of this Section, to 
26UIC permit applications under subsection (e) of this Section, 
 
 
10400SB0025ham004- 926 -LRB104 16098 AAS 29398 a

1or to CCR surface impoundment applications under subsection 
2(y) of this Section.
3    The Agency shall publish notice of all final permit 
4determinations for development permits for MSWLF units and for 
5significant permit modifications for lateral expansions for 
6existing MSWLF units one time in a newspaper of general 
7circulation in the county in which the unit is or is proposed 
8to be located.
9    After January 1, 1994 and until July 1, 1998, operating 
10permits issued under this Section by the Agency for sources of 
11air pollution permitted to emit less than 25 tons per year of 
12any combination of regulated air pollutants, as defined in 
13Section 39.5 of this Act, shall be required to be renewed only 
14upon written request by the Agency consistent with applicable 
15provisions of this Act and regulations promulgated hereunder. 
16Such operating permits shall expire 180 days after the date of 
17such a request. The Board shall revise its regulations for the 
18existing State air pollution operating permit program 
19consistent with this provision by January 1, 1994.
20    After June 30, 1998, operating permits issued under this 
21Section by the Agency for sources of air pollution that are not 
22subject to Section 39.5 of this Act and are not required to 
23have a federally enforceable State operating permit shall be 
24required to be renewed only upon written request by the Agency 
25consistent with applicable provisions of this Act and its 
26rules. Such operating permits shall expire 180 days after the 
 
 
10400SB0025ham004- 927 -LRB104 16098 AAS 29398 a

1date of such a request. Before July 1, 1998, the Board shall 
2revise its rules for the existing State air pollution 
3operating permit program consistent with this paragraph and 
4shall adopt rules that require a source to demonstrate that it 
5qualifies for a permit under this paragraph.
6    Each air pollution construction permit for diesel powered 
7backup generators to a source that is a data center, as defined 
8in subsection (c) of Section 605-1025 of the Department of 
9Commerce and Economic Opportunity Law of the Civil 
10Administrative Code of Illinois, that is applied for 6 months 
11after the effective date of this amendatory Act of the 104th 
12General Assembly and that is required to have a federally 
13enforceable State operating permit or a Clean Air Act Permit 
14Program permit shall, in addition to any other applicable 
15requirements, require each backup generator to: (i) meet 
16standards at least as protective as Tier 4 standards for 
17non-road diesel engines set out by the United States 
18Environmental Protection Agency in 40 CFR 1039, as it exists 
19on the effective date of this amendatory Act of the 104th 
20General Assembly, and (ii) operate solely as an emergency or 
21standby unit in accordance with 35 Ill. Adm. Code 211.1920, as 
22it exists on the effective date of this amendatory Act of the 
23104th General Assembly. If a diesel powered backup generator 
24becomes out of compliance with the Tier 4 standards for 
25non-road compression-ignition engines during a power outage, 
26the backup generator may (1) continue to operate for up to 24 
 
 
10400SB0025ham004- 928 -LRB104 16098 AAS 29398 a

1sequential hours after becoming noncompliant with the Tier 4 
2standards or (2) operate when compliance is achieved. 
3Notwithstanding any provision of law to the contrary, 
4operation of the backup generator for up to 24 sequential 
5hours after becoming noncompliant with the Tier 4 standards 
6shall not be considered a violation of the permit.    
7    Each air pollution construction permit for natural gas 
8powered backup generators for a source that is a data center, 
9as defined in subsection (c) of Section 605-1025 of the 
10Department of Commerce and Economic Opportunity Law of the 
11Civil Administrative Code of Illinois, that is applied for 6 
12months after the effective date of this amendatory Act of the 
13104th General Assembly and that is required to have a 
14federally enforceable State operating permit or a Clean Air 
15Act Permit Program permit shall, in addition to any other 
16applicable requirements, require each backup generator to: (i) 
17meet standards at least as protective as Tier 2 standards for 
18non-road large spark-ignition engines set out by the United 
19States Environmental Protection Agency in 40 CFR 1048, as it 
20exists on the effective date of this amendatory Act of the 
21104th General Assembly, and (ii) operate solely as an 
22emergency or standby unit in accordance with 35 Ill. Adm. Code 
23211.1920, as it exists on the effective date of this 
24amendatory Act of the 104th General Assembly. If a natural gas 
25powered backup generator becomes out of compliance with the 
26Tier 2 standards for non-road large spark-ignition engines 
 
 
10400SB0025ham004- 929 -LRB104 16098 AAS 29398 a

1during a power outage, the backup generator may (1) continue 
2to operate for up to 24 sequential hours after becoming 
3noncompliant with the Tier 2 standards or (2) operate when 
4compliance is achieved. Notwithstanding any provision of law 
5to the contrary, operation of the backup generator for up to 24 
6sequential hours after becoming noncompliant with the Tier 2 
7standards shall not be considered a violation of the permit.    
8    (b) The Agency may issue NPDES permits exclusively under 
9this subsection for the discharge of contaminants from point 
10sources into navigable waters, all as defined in the Federal 
11Water Pollution Control Act, as now or hereafter amended, 
12within the jurisdiction of the State, or into any well.
13    All NPDES permits shall contain those terms and 
14conditions, including, but not limited to, schedules of 
15compliance, which may be required to accomplish the purposes 
16and provisions of this Act.
17    The Agency may issue general NPDES permits for discharges 
18from categories of point sources which are subject to the same 
19permit limitations and conditions. Such general permits may be 
20issued without individual applications and shall conform to 
21regulations promulgated under Section 402 of the Federal Water 
22Pollution Control Act, as now or hereafter amended.
23    The Agency may include, among such conditions, effluent 
24limitations and other requirements established under this Act, 
25Board regulations, the Federal Water Pollution Control Act, as 
26now or hereafter amended, and regulations pursuant thereto, 
 
 
10400SB0025ham004- 930 -LRB104 16098 AAS 29398 a

1and schedules for achieving compliance therewith at the 
2earliest reasonable date.
3    The Agency shall adopt filing requirements and procedures 
4which are necessary and appropriate for the issuance of NPDES 
5permits, and which are consistent with the Act or regulations 
6adopted by the Board, and with the Federal Water Pollution 
7Control Act, as now or hereafter amended, and regulations 
8pursuant thereto.
9    The Agency, subject to any conditions which may be 
10prescribed by Board regulations, may issue NPDES permits to 
11allow discharges beyond deadlines established by this Act or 
12by regulations of the Board without the requirement of a 
13variance, subject to the Federal Water Pollution Control Act, 
14as now or hereafter amended, and regulations pursuant thereto.
15    (c) Except for those facilities owned or operated by 
16sanitary districts organized under the Metropolitan Water 
17Reclamation District Act, no permit for the development or 
18construction of a new pollution control facility may be 
19granted by the Agency unless the applicant submits proof to 
20the Agency that the location of the facility has been approved 
21by the county board of the county if in an unincorporated area, 
22or the governing body of the municipality when in an 
23incorporated area, in which the facility is to be located in 
24accordance with Section 39.2 of this Act. For purposes of this 
25subsection (c), and for purposes of Section 39.2 of this Act, 
26the appropriate county board or governing body of the 
 
 
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1municipality shall be the county board of the county or the 
2governing body of the municipality in which the facility is to 
3be located as of the date when the application for siting 
4approval is filed. 
5    In the event that siting approval granted pursuant to 
6Section 39.2 has been transferred to a subsequent owner or 
7operator, that subsequent owner or operator may apply to the 
8Agency for, and the Agency may grant, a development or 
9construction permit for the facility for which local siting 
10approval was granted. Upon application to the Agency for a 
11development or construction permit by that subsequent owner or 
12operator, the permit applicant shall cause written notice of 
13the permit application to be served upon the appropriate 
14county board or governing body of the municipality that 
15granted siting approval for that facility and upon any party 
16to the siting proceeding pursuant to which siting approval was 
17granted. In that event, the Agency shall conduct an evaluation 
18of the subsequent owner or operator's prior experience in 
19waste management operations in the manner conducted under 
20subsection (i) of Section 39 of this Act.
21    Beginning August 20, 1993, if the pollution control 
22facility consists of a hazardous or solid waste disposal 
23facility for which the proposed site is located in an 
24unincorporated area of a county with a population of less than 
25100,000 and includes all or a portion of a parcel of land that 
26was, on April 1, 1993, adjacent to a municipality having a 
 
 
10400SB0025ham004- 932 -LRB104 16098 AAS 29398 a

1population of less than 5,000, then the local siting review 
2required under this subsection (c) in conjunction with any 
3permit applied for after that date shall be performed by the 
4governing body of that adjacent municipality rather than the 
5county board of the county in which the proposed site is 
6located; and for the purposes of that local siting review, any 
7references in this Act to the county board shall be deemed to 
8mean the governing body of that adjacent municipality; 
9provided, however, that the provisions of this paragraph shall 
10not apply to any proposed site which was, on April 1, 1993, 
11owned in whole or in part by another municipality.
12    In the case of a pollution control facility for which a 
13development permit was issued before November 12, 1981, if an 
14operating permit has not been issued by the Agency prior to 
15August 31, 1989 for any portion of the facility, then the 
16Agency may not issue or renew any development permit nor issue 
17an original operating permit for any portion of such facility 
18unless the applicant has submitted proof to the Agency that 
19the location of the facility has been approved by the 
20appropriate county board or municipal governing body pursuant 
21to Section 39.2 of this Act.
22    After January 1, 1994, if a solid waste disposal facility, 
23any portion for which an operating permit has been issued by 
24the Agency, has not accepted waste disposal for 5 or more 
25consecutive calendar years, before that facility may accept 
26any new or additional waste for disposal, the owner and 
 
 
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1operator must obtain a new operating permit under this Act for 
2that facility unless the owner and operator have applied to 
3the Agency for a permit authorizing the temporary suspension 
4of waste acceptance. The Agency may not issue a new operation 
5permit under this Act for the facility unless the applicant 
6has submitted proof to the Agency that the location of the 
7facility has been approved or re-approved by the appropriate 
8county board or municipal governing body under Section 39.2 of 
9this Act after the facility ceased accepting waste.
10    Except for those facilities owned or operated by sanitary 
11districts organized under the Metropolitan Water Reclamation 
12District Act, and except for new pollution control facilities 
13governed by Section 39.2, and except for fossil fuel mining 
14facilities, the granting of a permit under this Act shall not 
15relieve the applicant from meeting and securing all necessary 
16zoning approvals from the unit of government having zoning 
17jurisdiction over the proposed facility.
18    Before beginning construction on any new sewage treatment 
19plant or sludge drying site to be owned or operated by a 
20sanitary district organized under the Metropolitan Water 
21Reclamation District Act for which a new permit (rather than 
22the renewal or amendment of an existing permit) is required, 
23such sanitary district shall hold a public hearing within the 
24municipality within which the proposed facility is to be 
25located, or within the nearest community if the proposed 
26facility is to be located within an unincorporated area, at 
 
 
10400SB0025ham004- 934 -LRB104 16098 AAS 29398 a

1which information concerning the proposed facility shall be 
2made available to the public, and members of the public shall 
3be given the opportunity to express their views concerning the 
4proposed facility.
5    The Agency may issue a permit for a municipal waste 
6transfer station without requiring approval pursuant to 
7Section 39.2 provided that the following demonstration is 
8made:
9        (1) the municipal waste transfer station was in 
10    existence on or before January 1, 1979 and was in 
11    continuous operation from January 1, 1979 to January 1, 
12    1993;
13        (2) the operator submitted a permit application to the 
14    Agency to develop and operate the municipal waste transfer 
15    station during April of 1994;
16        (3) the operator can demonstrate that the county board 
17    of the county, if the municipal waste transfer station is 
18    in an unincorporated area, or the governing body of the 
19    municipality, if the station is in an incorporated area, 
20    does not object to resumption of the operation of the 
21    station; and
22        (4) the site has local zoning approval.
23    (d) The Agency may issue RCRA permits exclusively under 
24this subsection to persons owning or operating a facility for 
25the treatment, storage, or disposal of hazardous waste as 
26defined under this Act. Subsection (y) of this Section, rather 
 
 
10400SB0025ham004- 935 -LRB104 16098 AAS 29398 a

1than this subsection (d), shall apply to permits issued for 
2CCR surface impoundments. 
3    All RCRA permits shall contain those terms and conditions, 
4including, but not limited to, schedules of compliance, which 
5may be required to accomplish the purposes and provisions of 
6this Act. The Agency may include among such conditions 
7standards and other requirements established under this Act, 
8Board regulations, the Resource Conservation and Recovery Act 
9of 1976 (P.L. 94-580), as amended, and regulations pursuant 
10thereto, and may include schedules for achieving compliance 
11therewith as soon as possible. The Agency shall require that a 
12performance bond or other security be provided as a condition 
13for the issuance of a RCRA permit.
14    In the case of a permit to operate a hazardous waste or PCB 
15incinerator as defined in subsection (k) of Section 44, the 
16Agency shall require, as a condition of the permit, that the 
17operator of the facility perform such analyses of the waste to 
18be incinerated as may be necessary and appropriate to ensure 
19the safe operation of the incinerator.
20    The Agency shall adopt filing requirements and procedures 
21which are necessary and appropriate for the issuance of RCRA 
22permits, and which are consistent with the Act or regulations 
23adopted by the Board, and with the Resource Conservation and 
24Recovery Act of 1976 (P.L. 94-580), as amended, and 
25regulations pursuant thereto.
26    The applicant shall make available to the public for 
 
 
10400SB0025ham004- 936 -LRB104 16098 AAS 29398 a

1inspection all documents submitted by the applicant to the 
2Agency in furtherance of an application, with the exception of 
3trade secrets, at the office of the county board or governing 
4body of the municipality. Such documents may be copied upon 
5payment of the actual cost of reproduction during regular 
6business hours of the local office. The Agency shall issue a 
7written statement concurrent with its grant or denial of the 
8permit explaining the basis for its decision.
9    (e) The Agency may issue UIC permits exclusively under 
10this subsection to persons owning or operating a facility for 
11the underground injection of contaminants as defined under 
12this Act.
13    All UIC permits shall contain those terms and conditions, 
14including, but not limited to, schedules of compliance, which 
15may be required to accomplish the purposes and provisions of 
16this Act. The Agency may include among such conditions 
17standards and other requirements established under this Act, 
18Board regulations, the Safe Drinking Water Act (P.L. 93-523), 
19as amended, and regulations pursuant thereto, and may include 
20schedules for achieving compliance therewith. The Agency shall 
21require that a performance bond or other security be provided 
22as a condition for the issuance of a UIC permit.
23    The Agency shall adopt filing requirements and procedures 
24which are necessary and appropriate for the issuance of UIC 
25permits, and which are consistent with the Act or regulations 
26adopted by the Board, and with the Safe Drinking Water Act 
 
 
10400SB0025ham004- 937 -LRB104 16098 AAS 29398 a

1(P.L. 93-523), as amended, and regulations pursuant thereto.
2    The applicant shall make available to the public for 
3inspection all documents submitted by the applicant to the 
4Agency in furtherance of an application, with the exception of 
5trade secrets, at the office of the county board or governing 
6body of the municipality. Such documents may be copied upon 
7payment of the actual cost of reproduction during regular 
8business hours of the local office. The Agency shall issue a 
9written statement concurrent with its grant or denial of the 
10permit explaining the basis for its decision.
11    (f) In making any determination pursuant to Section 9.1 of 
12this Act:
13        (1) The Agency shall have authority to make the 
14    determination of any question required to be determined by 
15    the Clean Air Act, as now or hereafter amended, this Act, 
16    or the regulations of the Board, including the 
17    determination of the Lowest Achievable Emission Rate, 
18    Maximum Achievable Control Technology, or Best Available 
19    Control Technology, consistent with the Board's 
20    regulations, if any.
21        (2) The Agency shall adopt requirements as necessary 
22    to implement public participation procedures, including, 
23    but not limited to, public notice, comment, and an 
24    opportunity for hearing, which must accompany the 
25    processing of applications for PSD permits. The Agency 
26    shall briefly describe and respond to all significant 
 
 
10400SB0025ham004- 938 -LRB104 16098 AAS 29398 a

1    comments on the draft permit raised during the public 
2    comment period or during any hearing. The Agency may group 
3    related comments together and provide one unified response 
4    for each issue raised.
5        (3) Any complete permit application submitted to the 
6    Agency under this subsection for a PSD permit shall be 
7    granted or denied by the Agency not later than one year 
8    after the filing of such completed application. 
9        (4) The Agency shall, after conferring with the 
10    applicant, give written notice to the applicant of its 
11    proposed decision on the application, including the terms 
12    and conditions of the permit to be issued and the facts, 
13    conduct, or other basis upon which the Agency will rely to 
14    support its proposed action.
15    (g) The Agency shall include as conditions upon all 
16permits issued for hazardous waste disposal sites such 
17restrictions upon the future use of such sites as are 
18reasonably necessary to protect public health and the 
19environment, including permanent prohibition of the use of 
20such sites for purposes which may create an unreasonable risk 
21of injury to human health or to the environment. After 
22administrative and judicial challenges to such restrictions 
23have been exhausted, the Agency shall file such restrictions 
24of record in the Office of the Recorder of the county in which 
25the hazardous waste disposal site is located.
26    (h) A hazardous waste stream may not be deposited in a 
 
 
10400SB0025ham004- 939 -LRB104 16098 AAS 29398 a

1permitted hazardous waste site unless specific authorization 
2is obtained from the Agency by the generator and disposal site 
3owner and operator for the deposit of that specific hazardous 
4waste stream. The Agency may grant specific authorization for 
5disposal of hazardous waste streams only after the generator 
6has reasonably demonstrated that, considering technological 
7feasibility and economic reasonableness, the hazardous waste 
8cannot be reasonably recycled for reuse, nor incinerated or 
9chemically, physically, or biologically treated so as to 
10neutralize the hazardous waste and render it nonhazardous. In 
11granting authorization under this Section, the Agency may 
12impose such conditions as may be necessary to accomplish the 
13purposes of the Act and are consistent with this Act and 
14regulations promulgated by the Board hereunder. If the Agency 
15refuses to grant authorization under this Section, the 
16applicant may appeal as if the Agency refused to grant a 
17permit, pursuant to the provisions of subsection (a) of 
18Section 40 of this Act. For purposes of this subsection (h), 
19the term "generator" has the meaning given in Section 3.205 of 
20this Act, unless: (1) the hazardous waste is treated, 
21incinerated, or partially recycled for reuse prior to 
22disposal, in which case the last person who treats, 
23incinerates, or partially recycles the hazardous waste prior 
24to disposal is the generator; or (2) the hazardous waste is 
25from a response action, in which case the person performing 
26the response action is the generator. This subsection (h) does 
 
 
10400SB0025ham004- 940 -LRB104 16098 AAS 29398 a

1not apply to any hazardous waste that is restricted from land 
2disposal under 35 Ill. Adm. Code 728.
3    (i) Before issuing any RCRA permit, any permit for a waste 
4storage site, sanitary landfill, waste disposal site, waste 
5transfer station, waste treatment facility, waste incinerator, 
6or any waste-transportation operation, any permit or interim 
7authorization for a clean construction or demolition debris 
8fill operation, or any permit required under subsection (d-5) 
9of Section 55, the Agency shall conduct an evaluation of the 
10prospective owner's or operator's prior experience in waste 
11management operations, clean construction or demolition debris 
12fill operations, and tire storage site management. The Agency 
13may deny such a permit, or deny or revoke interim 
14authorization, if the prospective owner or operator or any 
15employee or officer of the prospective owner or operator has a 
16history of:
17        (1) repeated violations of federal, State, or local 
18    laws, regulations, standards, or ordinances in the 
19    operation of waste management facilities or sites, clean 
20    construction or demolition debris fill operation 
21    facilities or sites, or tire storage sites; or
22        (2) conviction in this or another State of any crime 
23    which is a felony under the laws of this State, or 
24    conviction of a felony in a federal court; or conviction 
25    in this or another state or federal court of any of the 
26    following crimes: forgery, official misconduct, bribery, 
 
 
10400SB0025ham004- 941 -LRB104 16098 AAS 29398 a

1    perjury, or knowingly submitting false information under 
2    any environmental law, regulation, or permit term or 
3    condition; or
4        (3) proof of gross carelessness or incompetence in 
5    handling, storing, processing, transporting, or disposing 
6    of waste, clean construction or demolition debris, or used 
7    or waste tires, or proof of gross carelessness or 
8    incompetence in using clean construction or demolition 
9    debris as fill.
10    (i-5) Before issuing any permit or approving any interim 
11authorization for a clean construction or demolition debris 
12fill operation in which any ownership interest is transferred 
13between January 1, 2005, and the effective date of the 
14prohibition set forth in Section 22.52 of this Act, the Agency 
15shall conduct an evaluation of the operation if any previous 
16activities at the site or facility may have caused or allowed 
17contamination of the site. It shall be the responsibility of 
18the owner or operator seeking the permit or interim 
19authorization to provide to the Agency all of the information 
20necessary for the Agency to conduct its evaluation. The Agency 
21may deny a permit or interim authorization if previous 
22activities at the site may have caused or allowed 
23contamination at the site, unless such contamination is 
24authorized under any permit issued by the Agency. 
25    (j) The issuance under this Act of a permit to engage in 
26the surface mining of any resources other than fossil fuels 
 
 
10400SB0025ham004- 942 -LRB104 16098 AAS 29398 a

1shall not relieve the permittee from its duty to comply with 
2any applicable local law regulating the commencement, 
3location, or operation of surface mining facilities.
4    (k) A development permit issued under subsection (a) of 
5Section 39 for any facility or site which is required to have a 
6permit under subsection (d) of Section 21 shall expire at the 
7end of 2 calendar years from the date upon which it was issued, 
8unless within that period the applicant has taken action to 
9develop the facility or the site. In the event that review of 
10the conditions of the development permit is sought pursuant to 
11Section 40 or 41, or permittee is prevented from commencing 
12development of the facility or site by any other litigation 
13beyond the permittee's control, such two-year period shall be 
14deemed to begin on the date upon which such review process or 
15litigation is concluded.
16    (l) No permit shall be issued by the Agency under this Act 
17for construction or operation of any facility or site located 
18within the boundaries of any setback zone established pursuant 
19to this Act, where such construction or operation is 
20prohibited.
21    (m) The Agency may issue permits to persons owning or 
22operating a facility for composting landscape waste. In 
23granting such permits, the Agency may impose such conditions 
24as may be necessary to accomplish the purposes of this Act, and 
25as are not inconsistent with applicable regulations 
26promulgated by the Board. Except as otherwise provided in this 
 
 
10400SB0025ham004- 943 -LRB104 16098 AAS 29398 a

1Act, a bond or other security shall not be required as a 
2condition for the issuance of a permit. If the Agency denies 
3any permit pursuant to this subsection, the Agency shall 
4transmit to the applicant within the time limitations of this 
5subsection specific, detailed statements as to the reasons the 
6permit application was denied. Such statements shall include 
7but not be limited to the following:
8        (1) the Sections of this Act that may be violated if 
9    the permit were granted;
10        (2) the specific regulations promulgated pursuant to 
11    this Act that may be violated if the permit were granted;
12        (3) the specific information, if any, the Agency deems 
13    the applicant did not provide in its application to the 
14    Agency; and
15        (4) a statement of specific reasons why the Act and 
16    the regulations might be violated if the permit were 
17    granted.
18    If no final action is taken by the Agency within 90 days 
19after the filing of the application for permit, the applicant 
20may deem the permit issued. Any applicant for a permit may 
21waive the 90-day limitation by filing a written statement with 
22the Agency.
23    The Agency shall issue permits for such facilities upon 
24receipt of an application that includes a legal description of 
25the site, a topographic map of the site drawn to the scale of 
26200 feet to the inch or larger, a description of the operation, 
 
 
10400SB0025ham004- 944 -LRB104 16098 AAS 29398 a

1including the area served, an estimate of the volume of 
2materials to be processed, and documentation that:
3        (1) the facility includes a setback of at least 200 
4    feet from the nearest potable water supply well;
5        (2) the facility is located outside the boundary of 
6    the 10-year floodplain or the site will be floodproofed;
7        (3) the facility is located so as to minimize 
8    incompatibility with the character of the surrounding 
9    area, including at least a 200 foot setback from any 
10    residence, and in the case of a facility that is developed 
11    or the permitted composting area of which is expanded 
12    after November 17, 1991, the composting area is located at 
13    least 1/8 mile from the nearest residence (other than a 
14    residence located on the same property as the facility);
15        (4) the design of the facility will prevent any 
16    compost material from being placed within 5 feet of the 
17    water table, will adequately control runoff from the site, 
18    and will collect and manage any leachate that is generated 
19    on the site;
20        (5) the operation of the facility will include 
21    appropriate dust and odor control measures, limitations on 
22    operating hours, appropriate noise control measures for 
23    shredding, chipping and similar equipment, management 
24    procedures for composting, containment and disposal of 
25    non-compostable wastes, procedures to be used for 
26    terminating operations at the site, and recordkeeping 
 
 
10400SB0025ham004- 945 -LRB104 16098 AAS 29398 a

1    sufficient to document the amount of materials received, 
2    composted, and otherwise disposed of; and
3        (6) the operation will be conducted in accordance with 
4    any applicable rules adopted by the Board.
5    The Agency shall issue renewable permits of not longer 
6than 10 years in duration for the composting of landscape 
7wastes, as defined in Section 3.155 of this Act, based on the 
8above requirements.
9    The operator of any facility permitted under this 
10subsection (m) must submit a written annual statement to the 
11Agency on or before April 1 of each year that includes an 
12estimate of the amount of material, in tons, received for 
13composting.
14    (n) The Agency shall issue permits jointly with the 
15Department of Transportation for the dredging or deposit of 
16material in Lake Michigan in accordance with Section 18 of the 
17Rivers, Lakes, and Streams Act.
18    (o) (Blank).
19    (p) (1) Any person submitting an application for a permit 
20for a new MSWLF unit or for a lateral expansion under 
21subsection (t) of Section 21 of this Act for an existing MSWLF 
22unit that has not received and is not subject to local siting 
23approval under Section 39.2 of this Act shall publish notice 
24of the application in a newspaper of general circulation in 
25the county in which the MSWLF unit is or is proposed to be 
26located. The notice must be published at least 15 days before 
 
 
10400SB0025ham004- 946 -LRB104 16098 AAS 29398 a

1submission of the permit application to the Agency. The notice 
2shall state the name and address of the applicant, the 
3location of the MSWLF unit or proposed MSWLF unit, the nature 
4and size of the MSWLF unit or proposed MSWLF unit, the nature 
5of the activity proposed, the probable life of the proposed 
6activity, the date the permit application will be submitted, 
7and a statement that persons may file written comments with 
8the Agency concerning the permit application within 30 days 
9after the filing of the permit application unless the time 
10period to submit comments is extended by the Agency.
11    When a permit applicant submits information to the Agency 
12to supplement a permit application being reviewed by the 
13Agency, the applicant shall not be required to reissue the 
14notice under this subsection.
15    (2) The Agency shall accept written comments concerning 
16the permit application that are postmarked no later than 30 
17days after the filing of the permit application, unless the 
18time period to accept comments is extended by the Agency.
19    (3) Each applicant for a permit described in part (1) of 
20this subsection shall file a copy of the permit application 
21with the county board or governing body of the municipality in 
22which the MSWLF unit is or is proposed to be located at the 
23same time the application is submitted to the Agency. The 
24permit application filed with the county board or governing 
25body of the municipality shall include all documents submitted 
26to or to be submitted to the Agency, except trade secrets as 
 
 
10400SB0025ham004- 947 -LRB104 16098 AAS 29398 a

1determined under Section 7.1 of this Act. The permit 
2application and other documents on file with the county board 
3or governing body of the municipality shall be made available 
4for public inspection during regular business hours at the 
5office of the county board or the governing body of the 
6municipality and may be copied upon payment of the actual cost 
7of reproduction.
8    (q) Within 6 months after July 12, 2011 (the effective 
9date of Public Act 97-95), the Agency, in consultation with 
10the regulated community, shall develop a web portal to be 
11posted on its website for the purpose of enhancing review and 
12promoting timely issuance of permits required by this Act. At 
13a minimum, the Agency shall make the following information 
14available on the web portal:
15        (1) Checklists and guidance relating to the completion 
16    of permit applications, developed pursuant to subsection 
17    (s) of this Section, which may include, but are not 
18    limited to, existing instructions for completing the 
19    applications and examples of complete applications. As the 
20    Agency develops new checklists and develops guidance, it 
21    shall supplement the web portal with those materials.
22        (2) Within 2 years after July 12, 2011 (the effective 
23    date of Public Act 97-95), permit application forms or 
24    portions of permit applications that can be completed and 
25    saved electronically, and submitted to the Agency 
26    electronically with digital signatures.
 
 
10400SB0025ham004- 948 -LRB104 16098 AAS 29398 a

1        (3) Within 2 years after July 12, 2011 (the effective 
2    date of Public Act 97-95), an online tracking system where 
3    an applicant may review the status of its pending 
4    application, including the name and contact information of 
5    the permit analyst assigned to the application. Until the 
6    online tracking system has been developed, the Agency 
7    shall post on its website semi-annual permitting 
8    efficiency tracking reports that include statistics on the 
9    timeframes for Agency action on the following types of 
10    permits received after July 12, 2011 (the effective date 
11    of Public Act 97-95): air construction permits, new NPDES 
12    permits and associated water construction permits, and 
13    modifications of major NPDES permits and associated water 
14    construction permits. The reports must be posted by 
15    February 1 and August 1 each year and shall include:
16            (A) the number of applications received for each 
17        type of permit, the number of applications on which 
18        the Agency has taken action, and the number of 
19        applications still pending; and
20            (B) for those applications where the Agency has 
21        not taken action in accordance with the timeframes set 
22        forth in this Act, the date the application was 
23        received and the reasons for any delays, which may 
24        include, but shall not be limited to, (i) the 
25        application being inadequate or incomplete, (ii) 
26        scientific or technical disagreements with the 
 
 
10400SB0025ham004- 949 -LRB104 16098 AAS 29398 a

1        applicant, USEPA, or other local, state, or federal 
2        agencies involved in the permitting approval process, 
3        (iii) public opposition to the permit, or (iv) Agency 
4        staffing shortages. To the extent practicable, the 
5        tracking report shall provide approximate dates when 
6        cause for delay was identified by the Agency, when the 
7        Agency informed the applicant of the problem leading 
8        to the delay, and when the applicant remedied the 
9        reason for the delay.
10    (r) Upon the request of the applicant, the Agency shall 
11notify the applicant of the permit analyst assigned to the 
12application upon its receipt.
13    (s) The Agency is authorized to prepare and distribute 
14guidance documents relating to its administration of this 
15Section and procedural rules implementing this Section. 
16Guidance documents prepared under this subsection shall not be 
17considered rules and shall not be subject to the Illinois 
18Administrative Procedure Act. Such guidance shall not be 
19binding on any party.
20    (t) Except as otherwise prohibited by federal law or 
21regulation, any person submitting an application for a permit 
22may include with the application suggested permit language for 
23Agency consideration. The Agency is not obligated to use the 
24suggested language or any portion thereof in its permitting 
25decision. If requested by the permit applicant, the Agency 
26shall meet with the applicant to discuss the suggested 
 
 
10400SB0025ham004- 950 -LRB104 16098 AAS 29398 a

1language.
2    (u) If requested by the permit applicant, the Agency shall 
3provide the permit applicant with a copy of the draft permit 
4prior to any public review period.
5    (v) If requested by the permit applicant, the Agency shall 
6provide the permit applicant with a copy of the final permit 
7prior to its issuance. 
8    (w) An air pollution permit shall not be required due to 
9emissions of greenhouse gases, as specified by Section 9.15 of 
10this Act.
11    (x) If, before the expiration of a State operating permit 
12that is issued pursuant to subsection (a) of this Section and 
13contains federally enforceable conditions limiting the 
14potential to emit of the source to a level below the major 
15source threshold for that source so as to exclude the source 
16from the Clean Air Act Permit Program, the Agency receives a 
17complete application for the renewal of that permit, then all 
18of the terms and conditions of the permit shall remain in 
19effect until final administrative action has been taken on the 
20application for the renewal of the permit. 
21    (y) The Agency may issue permits exclusively under this 
22subsection to persons owning or operating a CCR surface 
23impoundment subject to Section 22.59.
24    (z) If a mass animal mortality event is declared by the 
25Department of Agriculture in accordance with the Animal 
26Mortality Act:
 
 
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1        (1) the owner or operator responsible for the disposal 
2    of dead animals is exempted from the following:
3            (i) obtaining a permit for the construction, 
4        installation, or operation of any type of facility or 
5        equipment issued in accordance with subsection (a) of 
6        this Section;
7            (ii) obtaining a permit for open burning in 
8        accordance with the rules adopted by the Board; and
9            (iii) registering the disposal of dead animals as 
10        an eligible small source with the Agency in accordance 
11        with Section 9.14 of this Act; 
12        (2) as applicable, the owner or operator responsible 
13    for the disposal of dead animals is required to obtain the 
14    following permits:
15            (i) an NPDES permit in accordance with subsection 
16        (b) of this Section;
17            (ii) a PSD permit or an NA NSR permit in accordance 
18        with Section 9.1 of this Act;
19            (iii) a lifetime State operating permit or a 
20        federally enforceable State operating permit, in 
21        accordance with subsection (a) of this Section; or
22            (iv) a CAAPP permit, in accordance with Section 
23        39.5 of this Act. 
24    All CCR surface impoundment permits shall contain those 
25terms and conditions, including, but not limited to, schedules 
26of compliance, which may be required to accomplish the 
 
 
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1purposes and provisions of this Act, Board regulations, the 
2Illinois Groundwater Protection Act and regulations pursuant 
3thereto, and the Resource Conservation and Recovery Act and 
4regulations pursuant thereto, and may include schedules for 
5achieving compliance therewith as soon as possible.
6    The Board shall adopt filing requirements and procedures 
7that are necessary and appropriate for the issuance of CCR 
8surface impoundment permits and that are consistent with this 
9Act or regulations adopted by the Board, and with the RCRA, as 
10amended, and regulations pursuant thereto.
11    The applicant shall make available to the public for 
12inspection all documents submitted by the applicant to the 
13Agency in furtherance of an application, with the exception of 
14trade secrets, on its public internet website as well as at the 
15office of the county board or governing body of the 
16municipality where CCR from the CCR surface impoundment will 
17be permanently disposed. Such documents may be copied upon 
18payment of the actual cost of reproduction during regular 
19business hours of the local office.
20    The Agency shall issue a written statement concurrent with 
21its grant or denial of the permit explaining the basis for its 
22decision.
23(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22; 
24102-558, eff. 8-20-21; 102-813, eff. 5-13-22.)
 
25    Section 90-50. The Electric Vehicle Rebate Act is amended 
 
 
10400SB0025ham004- 953 -LRB104 16098 AAS 29398 a

1by changing Sections 35, 40, and 45 and by adding Section 36 as 
2follows:
 
3    (415 ILCS 120/35)
4    Sec. 35. User fees. 
5    (a) The Office of the Secretary of State shall collect 
6annual user fees from any individual, partnership, 
7association, corporation, or agency of the United States 
8government that registers any combination of 10 or more of the 
9following types of motor vehicles in the Covered Area: (1) 
10vehicles of the First Division, as defined in the Illinois 
11Vehicle Code; (2) vehicles of the Second Division registered 
12under the B, C, D, F, H, MD, MF, MG, MH and MJ plate 
13categories, as defined in the Illinois Vehicle Code; and (3) 
14commuter vans and livery vehicles as defined in the Illinois 
15Vehicle Code. This Section does not apply to vehicles 
16registered under the International Registration Plan under 
17Section 3-402.1 of the Illinois Vehicle Code. The user fee 
18shall be $20 for each vehicle registered in the Covered Area 
19for each fiscal year. The Office of the Secretary of State 
20shall collect the $20 when a vehicle's registration fee is 
21paid.
22    (b) Owners of State, county, and local government 
23vehicles, rental vehicles, antique vehicles, expanded-use 
24antique vehicles, electric vehicles, and motorcycles are 
25exempt from paying the user fees on such vehicles.
 
 
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1    (c) The Office of the Secretary of State shall deposit the 
2user fees collected into the Electric Vehicle and Charging    
3Rebate Fund.
4(Source: P.A. 101-505, eff. 1-1-20; 102-662, eff. 9-15-21.)
 
5    (415 ILCS 120/36 new)
6    Sec. 36. Electric vehicle and charging financial 
7assistance.    
8    (a) Beginning January 1, 2029, the Agency shall administer 
9grants and other forms of financial assistance to support the 
10electrification of the transportation sector, including 
11electric passenger vehicles, electric school buses and 
12electric transit buses, electric medium-duty and heavy-duty 
13trucks, and electric vehicle charging infrastructure. The 
14Agency shall also implement customer education and outreach 
15programs that increase awareness of the programs for and the 
16benefits of transportation electrification. The programs under 
17this Section shall be developed and implemented pursuant to 
18the goals outlined in Section 45 of the Electric Vehicle Act.
19    (b) No later than March 1, 2028, and every 3 years 
20thereafter, the Agency shall publish a draft Transportation 
21Electrification Plan that specifies the proposed programs and 
22allocation of funds for the following 3 calendar years. The 
23Agency shall solicit public comments on the design of the Plan 
24and the funding allocations and shall incorporate any public 
25comments into the final Plan. The Plan shall take into 
 
 
10400SB0025ham004- 955 -LRB104 16098 AAS 29398 a

1consideration lessons learned from the implementation of 
2utility Beneficial Electrification Plans under the Electric 
3Vehicle Act. Within 180 days after the publication of the 
4draft Plan, the Agency shall publish a final Plan.
5    (c) The Agency shall have broad authority to provide 
6grants and other forms of financial assistance to public and 
7private entities under this Section pursuant to the Grant 
8Accountability and Transparency Act. Awardees under this 
9Section shall comply with the requirements of the Prevailing 
10Wage Act for charging station installations. The Agency may 
11provide additional incentives for projects located in eligible 
12communities.
13    (d) Funds shall be made available from the Electric 
14Vehicle and Charging Fund to the Agency pursuant to subsection 
15(c). The annual budget for Agency-administered transportation 
16electrification programs shall be equivalent to the annual 
17budget of programs administered by utilities under the 
18Electric Vehicle Act for the years 2026 through 2028.
 
19    (415 ILCS 120/40)
20    Sec. 40. Appropriations from the Electric Vehicle and 
21Charging Rebate Fund.     
22    (a) The Agency shall estimate the amount of user fees 
23expected to be collected under Section 35 of this Act for each 
24fiscal year. User fee funds shall be deposited into and 
25distributed from the Electric Vehicle and Charging Rebate Fund 
 
 
10400SB0025ham004- 956 -LRB104 16098 AAS 29398 a

1in the following manner:    
2        (1) Through fiscal year 2023, an annual amount not to 
3    exceed $225,000 may be appropriated to the Agency from the 
4    Electric Vehicle and Charging Rebate Fund to pay its costs 
5    of administering the programs authorized by Section 27 of 
6    this Act. Beginning in fiscal year 2024 and in each fiscal 
7    year thereafter, an annual amount not to exceed $600,000 
8    may be appropriated to the Agency from the Electric 
9    Vehicle and Charging Rebate Fund to pay its costs of 
10    administering the programs authorized by Section 27 of 
11    this Act. An amount not to exceed $225,000 may be 
12    appropriated to the Secretary of State from the Electric 
13    Vehicle and Charging Rebate Fund to pay the Secretary of 
14    State's costs of administering the programs authorized 
15    under this Act.    
16        (2) In fiscal year 2022 and each fiscal year 
17    thereafter, after appropriation of the amounts authorized 
18    by item (1) of subsection (a) of this Section, the 
19    remaining moneys estimated to be collected during each 
20    fiscal year shall be appropriated.    
21        (3) (Blank).    
22        (4) Moneys appropriated to fund the programs 
23    authorized in Sections 25 and 30 shall be expended only 
24    after they have been collected and deposited into the 
25    Electric Vehicle and Charging Rebate Fund.
26    (b) Amounts appropriated to and deposited into the 
 
 
10400SB0025ham004- 957 -LRB104 16098 AAS 29398 a

1Electric Vehicle and Charging Rebate Fund from the General 
2Revenue Fund, or any other fund, shall be distributed from the 
3Electric Vehicle and Charging Rebate Fund to fund the program 
4authorized in Section 27.
5(Source: P.A. 103-8, eff. 6-7-23; 103-363, eff. 7-28-23; 
6103-605, eff. 7-1-24; 104-6, eff. 7-1-25.)
 
7    (415 ILCS 120/45)
8    Sec. 45. Electric Vehicle and Charging Rebate Fund; 
9creation; deposit of user fees. A separate fund in the State 
10treasury Treasury called the Electric Vehicle and Charging    
11Rebate Fund is created, into which shall be transferred the 
12user fees as provided in Section 35, funds as provided in 
13Section 605-1075 of the Department of Commerce and Economic 
14Opportunity Law of the Civil Administrative Code of Illinois,    
15and any other revenues, deposits, State appropriations, 
16contributions, grants, gifts, bequests, legacies of money and 
17securities, or transfers as provided by law from, without 
18limitation, governmental entities, private sources, 
19foundations, trade associations, industry organizations, and 
20not-for-profit organizations.
21(Source: P.A. 102-662, eff. 9-15-21.)
 
22    Section 90-55. The Illinois Nuclear Safety Preparedness 
23Act is amended by changing Sections 3, 4, 5, 8, and 9 and by 
24adding Section 6.5 as follows:
 
 
 
10400SB0025ham004- 958 -LRB104 16098 AAS 29398 a

1    (420 ILCS 5/3)  (from Ch. 111 1/2, par. 4303)
2    Sec. 3. Definitions. Unless the context otherwise clearly 
3requires, as used in this Act:
4    (1) "Agency" or "IEMA-OHS" means the Illinois Emergency 
5Management Agency and Office of Homeland Security, or its 
6successor agency.
7    (2) "Director" means the Director of the Agency.
8    (2.5) "Emergency planning zone" means a generic area 
9around a commercial nuclear facility used to assist in 
10off-site emergency planning and the development of a 
11significant response base.    
12    (3) "Person" means any individual, corporation, 
13partnership, firm, association, trust, estate, public or 
14private institution, group, agency, political subdivision of 
15this State, any other state or political subdivision or agency 
16thereof, and any legal successor, representative, agent, or 
17agency of the foregoing.
18    (4) "NRC" means the United States Nuclear Regulatory 
19Commission or any agency which succeeds to its functions in 
20the licensing of nuclear power reactors or facilities for 
21storing spent nuclear fuel.
22    (5) "High-level radioactive waste" means (1) the highly 
23radioactive material resulting from the reprocessing of spent 
24nuclear fuel including liquid waste produced directly in 
25reprocessing and any solid material derived from such liquid 
 
 
10400SB0025ham004- 959 -LRB104 16098 AAS 29398 a

1waste that contains fission products in sufficient 
2concentrations; and (2) the highly radioactive material that 
3the NRC has determined to be high-level radioactive waste 
4requiring permanent isolation.
5    (6) "Nuclear facilities" means nuclear power plants, 
6facilities housing nuclear test and research reactors, 
7facilities for the chemical conversion of uranium, and 
8facilities for the storage of spent nuclear fuel or high-level 
9radioactive waste.
10    (7) "Spent nuclear fuel" means fuel that has been 
11withdrawn from a nuclear reactor following irradiation, the 
12constituent elements of which have not been separated by 
13reprocessing.
14    (8) "Transuranic waste" means material contaminated with 
15elements that have an atomic number greater than 92, including 
16neptunium, plutonium, americium, and curium, excluding 
17radioactive wastes shipped to a licensed low-level radioactive 
18waste disposal facility.
19    (9) "Highway route controlled quantity of radioactive 
20materials" means that quantity of radioactive materials 
21defined as a highway route controlled quantity under rules of 
22the United States Department of Transportation, or any 
23successor agency. 
24    (10) "Nuclear power plant" or "nuclear steam-generating 
25facility" means a thermal power plant in which the energy 
26(heat) released by the fissioning of nuclear fuel is used to 
 
 
10400SB0025ham004- 960 -LRB104 16098 AAS 29398 a

1boil water to produce steam.
2    (11) "Nuclear power reactor" means an apparatus, other 
3than an atomic weapon, designed or used to sustain nuclear 
4fission in a self-supporting chain reaction.
5    (12) (Blank). "Small modular reactor" or "SMR" means an 
6advanced nuclear reactor: (1) with a rated nameplate capacity 
7of 300 electrical megawatts or less; and (2) that may be 
8constructed and operated in combination with similar reactors 
9at a single site.
10    (13) "Site boundary" means the line beyond which the land 
11or property is not owned, leased, or otherwise controlled by 
12the licensee.    
13(Source: P.A. 103-569, eff. 6-1-24.)
 
14    (420 ILCS 5/4)  (from Ch. 111 1/2, par. 4304)
15    Sec. 4. Nuclear accident plans; fees.     
16    (a) Persons engaged within this State in the production of 
17electricity utilizing nuclear energy, the operation of nuclear 
18test and research reactors, the chemical conversion of 
19uranium, or the transportation, storage or possession of spent 
20nuclear fuel or high-level radioactive waste shall pay fees to 
21cover the cost of establishing plans and programs to deal with 
22the possibility of nuclear accidents. Except as provided 
23below, the fees shall be used to fund those Agency and local 
24government activities defined as necessary by the Director to 
25implement and maintain the plans and programs authorized by 
 
 
10400SB0025ham004- 961 -LRB104 16098 AAS 29398 a

1this Act. 
2    (b) Local governments incurring expenses attributable to 
3implementation and maintenance of the plans and programs 
4authorized by this Act may apply to the Agency for 
5compensation for those expenses, and upon approval by the 
6Director of applications submitted by local governments, the 
7Agency shall compensate local governments from fees collected 
8under this Section. The Agency shall, by rule, determine the 
9method for compensating local governments under this Section.    
10Compensation for local governments shall include $250,000 in 
11any year through fiscal year 1993, $275,000 in fiscal year 
121994 and fiscal year 1995, $300,000 in fiscal year 1996, 
13$400,000 in fiscal year 1997, and $450,000 in fiscal year 1998 
14and thereafter.    
15    (c) Appropriations to the Agency Department of Nuclear 
16Safety (of which the Agency is the successor) for compensation 
17to local governments from the Nuclear Safety Emergency 
18Preparedness Fund provided for in this Section shall not 
19exceed $1,500,000 $650,000 per State fiscal year. Expenditures 
20from these appropriations shall not exceed, in a single State 
21fiscal year, the annual compensation amount made available to 
22local governments under this Section, unexpended funds made 
23available for local government compensation in the previous 
24fiscal year, and funds recovered under the Illinois Grant 
25Funds Recovery Act during previous fiscal years. 
26Notwithstanding any other provision of this Act, the 
 
 
10400SB0025ham004- 962 -LRB104 16098 AAS 29398 a

1expenditure limitation for fiscal year 1998 shall include the 
2additional $100,000 made available to local governments for 
3fiscal year 1997 under this amendatory Act of 1997. The Agency 
4shall, by rule, determine the method for compensating local 
5governments under this Section. The appropriation shall not 
6exceed $500,000 in any year preceding fiscal year 1996; the 
7appropriation shall not exceed $625,000 in fiscal year 1996, 
8$725,000 in fiscal year 1997, and $775,000 in fiscal year 1998 
9and thereafter. The fees shall consist of the following:
10    (d) Persons operating commercial nuclear power reactors 
11shall pay fees as follows:    
12        (1) A one-time fee for each nuclear power reactor 
13    commencing operation in this State after January 1, 2026    
14    charge of $590,000 per nuclear power station in this State    
15    to be paid pursuant to Section 5 of this Act and according 
16    to the following: by the owners of the stations.
17            (A) $1,500,000 for a reactor located at a new site 
18        requiring an emergency planning zone;
19            (B) $500,000 for a reactor located on the site of a 
20        reactor that commenced operation prior to January 1, 
21        2026;
22            (C) $600,000 for a reactor located at a new site 
23        not requiring an emergency planning zone.
24        (1.5) For nuclear power reactors in operation on 
25    January 1, 2026, a one-time fee of $500,000 per nuclear 
26    power reactor in this State to be paid pursuant to Section 
 
 
10400SB0025ham004- 963 -LRB104 16098 AAS 29398 a

1    5 of this Act.    
2        (2) For nuclear power reactors that have a plume 
3    exposure pathway emergency planning zone that extends 
4    beyond the site boundary, an annual fee per nuclear power 
5    reactor shall be as follows: An additional charge of 
6    $240,000 per nuclear power station for which a fee under 
7    subparagraph (1) was paid before June 30, 1982.
8            (A) For the first fiscal year following the 
9        effective date of this amendatory Act of the 104th 
10        General Assembly, the base fee shall be $3,900,000 per 
11        operating reactor.
12            (B) For each of the 9 fiscal years after the 
13        effective date of this amendatory Act of the 104th 
14        General Assembly, the base fee shall be increased 
15        annually by 1.5% of the prior fiscal year's fee.
16            (C) The annual adjustment described in 
17        subparagraph (B) of this paragraph (2) shall terminate 
18        after the tenth fiscal year. Beginning with the 11th 
19        fiscal year, and for each fiscal year thereafter, the 
20        base fee shall remain at the amount established in the 
21        tenth fiscal year and shall not be subject to further 
22        automatic increases under this Section, unless and 
23        until this subparagraph (C) is amended by the General 
24        Assembly.
25            (D) Payment shall be made pursuant to Section 5 of 
26        this Act.
 
 
10400SB0025ham004- 964 -LRB104 16098 AAS 29398 a

1        (3) For nuclear power reactors not required to have an 
2    emergency planning zone, the annual fee per nuclear 
3    reactor shall be $750,000 until the NRC terminates the 
4    license. Through June 30, 1982, an annual fee of $75,000 
5    per year for each nuclear power reactor for which an 
6    operating license has been issued by the NRC, and after 
7    June 30, 1982, and through June 30, 1984 an annual fee of 
8    $180,000 per year for each nuclear power reactor for which 
9    an operating license has been issued by the NRC, and after 
10    June 30, 1984, and through June 30, 1991, an annual fee of 
11    $400,000 for each nuclear power reactor for which an 
12    operating license has been issued by the NRC, to be paid by 
13    the owners of nuclear power reactors operating in this 
14    State. After June 30, 1991, the owners of nuclear power 
15    reactors in this State for which operating licenses have 
16    been issued by the NRC shall pay the following fees for 
17    each such nuclear power reactor: for State fiscal year 
18    1992, $925,000; for State fiscal year 1993, $975,000; for 
19    State fiscal year 1994; $1,010,000; for State fiscal year 
20    1995, $1,060,000; for State fiscal years 1996 and 1997, 
21    $1,110,000; for State fiscal year 1998, $1,314,000; for 
22    State fiscal year 1999, $1,368,000; for State fiscal year 
23    2000, $1,404,000; for State fiscal year 2001, $1,696,455; 
24    for State fiscal year 2002, $1,730,636; for State fiscal 
25    year 2003 through State fiscal year 2011, $1,757,727; for 
26    State fiscal year 2012 and subsequent fiscal years, 
 
 
10400SB0025ham004- 965 -LRB104 16098 AAS 29398 a

1    $1,903,182.
2        (3.5) The owner of a nuclear power reactor that 
3    notifies the Nuclear Regulatory Commission that the 
4    nuclear power reactor has permanently ceased operations 
5    during State fiscal year 1998 shall pay the following fees 
6    for each such nuclear power reactor: $1,368,000 for State 
7    fiscal year 1999 and $1,404,000 for State fiscal year 
8    2000.
9        (4) For nuclear power reactors with an emergency 
10    planning zone constructed on a new site after January 1, 
11    2026, the operator or the owner shall reimburse the Agency 
12    for the actual costs of any equipment, materials, and 
13    labor provided for development, installation, and 
14    maintenance of monitoring systems as required under 
15    paragraphs (1), (2), (3), and (7) of subsection (a) of 
16    Section 8 of this Act. The operator or owner shall be 
17    invoiced by the Agency and payment shall be due within 60 
18    days after the date of the invoice. A capital expenditure 
19    surcharge of $1,400,000 per nuclear power station in this 
20    State, whether operating or under construction, shall be 
21    paid by the owners of the station.
22        (5) An annual fee of $25,000 per year for each site for 
23    which a valid operating license has been issued by NRC for 
24    the operation of an away-from-reactor spent nuclear fuel 
25    or high-level radioactive waste storage facility, to be 
26    paid by the owners of facilities for the storage of spent 
 
 
10400SB0025ham004- 966 -LRB104 16098 AAS 29398 a

1    nuclear fuel or high-level radioactive waste for others in 
2    this State.
3        (6) A one-time charge of $280,000 for each facility in 
4    this State housing a nuclear test and research reactor, to 
5    be paid by the operator of the facility. However, this 
6    charge shall not be required to be paid by any 
7    tax-supported institution.
8        (7) A one-time charge of $50,000 for each facility in 
9    this State for the chemical conversion of uranium, to be 
10    paid by the owner of the facility.
11        (8) An annual fee of $150,000 per year for each 
12    facility in this State housing a nuclear test and research 
13    reactor, to be paid by the operator of the facility. 
14    However, this annual fee shall not be required to be paid 
15    by any tax-supported institution.
16        (9) An annual fee of $15,000 per year for each 
17    facility in this State for the chemical conversion of 
18    uranium, to be paid by the owner of the facility.
19        (10) A fee assessed at the rate of $2,500 per truck for 
20    each truck shipment and $4,500 for the first cask and 
21    $3,000 for each additional cask for each rail shipment of 
22    spent nuclear fuel, high-level radioactive waste, 
23    transuranic waste, or a highway route controlled quantity 
24    of radioactive materials received at or departing from any 
25    nuclear power station or away-from-reactor spent nuclear 
26    fuel, high-level radioactive waste, transuranic waste 
 
 
10400SB0025ham004- 967 -LRB104 16098 AAS 29398 a

1    storage facility, or other facility in this State to be 
2    paid by the shipper of the spent nuclear fuel, high level 
3    radioactive waste, transuranic waste, or highway route 
4    controlled quantity of radioactive material. Truck 
5    shipments of greater than 250 miles in Illinois are 
6    subject to a surcharge of $25 per mile over 250 miles for 
7    each truck in the shipment.
8        (11) 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 traversing the State to be paid 
14    by the shipper of the spent nuclear fuel, high level 
15    radioactive waste, transuranic waste, or highway route 
16    controlled quantity of radioactive material. Truck 
17    shipments of greater than 250 miles in Illinois are 
18    subject to a surcharge of $25 per mile over 250 miles for 
19    each truck in the shipment. For truck shipments of less 
20    than 100 miles in Illinois that consist entirely of 
21    cobalt-60 or other medical isotopes or both, the $2,500 
22    per truck fee shall be reduced to $1,500 for the first 
23    truck and $750 for each additional truck in the same 
24    shipment. 
25        (12) In each of the State fiscal years 1988 through 
26    1991, in addition to the annual fee provided for in 
 
 
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1    subparagraph (3), a fee of $400,000 for each nuclear power 
2    reactor for which an operating license has been issued by 
3    the NRC, to be paid by the owners of nuclear power reactors 
4    operating in this State. Within 120 days after the end of 
5    the State fiscal years ending June 30, 1988, June 30, 
6    1989, June 30, 1990, and June 30, 1991, the Agency shall 
7    determine the expenses of the Illinois Nuclear Safety 
8    Preparedness Program paid from funds appropriated for 
9    those fiscal years.
10(Source: P.A. 97-195, eff. 7-25-11; 97-732, eff. 6-30-12; 
1198-728, eff. 1-1-15.)
 
12    (420 ILCS 5/5)  (from Ch. 111 1/2, par. 4305)
13    Sec. 5. Nuclear power reactor or spent fuel storage 
14facility operating license fees.        
15    (a) Except as otherwise provided in this Section, within 
1630 days after the beginning of each State fiscal year, each 
17person who possessed a valid operating license issued by the 
18NRC for a nuclear power reactor or a spent fuel storage 
19facility during any portion of the previous fiscal year shall 
20pay to the Agency the fees imposed by Section 4 of this Act. 
21    (b) The one-time fee for new nuclear power reactors    
22facility charge assessed pursuant to subparagraph (1) of 
23subsection (d) of Section 4 of this Act shall be paid to the 
24Agency not less than 2 years prior to scheduled commencement 
25of commercial operation. The one-time fee is only applicable 
 
 
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1to nuclear power reactors constructed after January 1, 2026.    
2The additional facility charge assessed pursuant to 
3subparagraph (2) of Section 4 shall be paid to the Department 
4within 90 days of June 30, 1982. Fees assessed pursuant to 
5subparagraph (3) of Section 4 for State fiscal year 1992 shall 
6be payable as follows: $400,000 due on August 1, 1991, and 
7$525,000 due on January 1, 1992. Fees assessed pursuant to 
8subparagraph (3) of Section 4 for State fiscal years 1993 
9through 2011 shall be due and payable in two equal payments on 
10July 1 and January 1 during the fiscal year in which the fee is 
11due. For State fiscal year 2012 and subsequent fiscal years, 
12fees shall be due and payable in 4 equal payments on July 1, 
13October 1, January 1, and April 1 during the fiscal year in 
14which the fee is due. Fees assessed pursuant to subparagraph 
15(4) of Section 4 shall be paid in six payments, the first, in 
16the amount of $400,000, shall be due and payable 30 days after 
17the effective date of this Amendatory Act of 1984. Subsequent 
18payments shall be in the amount of $200,000 each, and shall be 
19due and payable annually on August 1, 1985 through August 1, 
201989, inclusive. Fees assessed under the provisions of 
21subparagraphs (6) and (7) of Section 4 of this Act shall be 
22paid on or before January 1, 1990. Fees assessed under the 
23provisions of subparagraphs (8) and (9) of Section 4 of this 
24Act shall be paid on or before January 1st of each year, 
25beginning January 1, 1990. Fees assessed under the provisions 
26of subparagraphs (10) and (11) of Section 4 of this Act shall 
 
 
10400SB0025ham004- 970 -LRB104 16098 AAS 29398 a

1be paid to the Agency within 60 days after completion of such 
2shipments within this State. Fees assessed pursuant to 
3subparagraph (12) of Section 4 shall be paid to the Agency by 
4each person who possessed a valid operating license issued by 
5the NRC for a nuclear power reactor during any portion of the 
6previous State fiscal year as follows: the fee due in fiscal 
7year 1988 shall be paid on January 15, 1988, the fee due in 
8fiscal year 1989 shall be paid on December 1, 1988, and 
9subsequent fees shall be paid annually on December 1, 1989 
10through December 1, 1990.
11    (c) The one-time fee assessed pursuant to subparagraph 
12(1.5) of subsection (d) of Section 4 of this Act shall be paid 
13in 4 equal installments to the Agency on July 1, 2026, October 
141, 2026, January 1, 2027, and April 1, 2027.
15    (d) The annual fee for each nuclear power reactor assessed 
16pursuant to subparagraphs (2) and (3) of subsection (d) of 
17Section 4 of this Act shall be paid in 4 equal installments to 
18the Agency on July 1, October 1, January 1, and April 1 of the 
19State fiscal year the fee is due.    
20    (e) Fees assessed under the provisions of subparagraphs 
21(8) and (9) of subsection (d) of Section 4 of this Act shall be 
22paid on or before January 1 of each year.    
23    (f) Fees assessed under the provisions of subparagraphs 
24(10) and (11) of subsection (d) of Section 4 of this Act shall 
25be paid to the Agency within 60 days after completion of such 
26shipments within this State.    
 
 
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1    (b) Fees assessed pursuant to paragraph (3.5) of Section 4 
2for State fiscal years 1999 and 2000 shall be due and payable 
3in 2 equal payments on July 1 and January 1 during the fiscal 
4year in which the fee is due. The fee due on July 1, 1998 shall 
5be payable on that date, or within 10 days after the effective 
6date of this amendatory Act of 1998, whichever is later.
7    (g) (c) Any person who fails to pay a fee assessed under 
8Section 4 of this Act within 90 days after the fee is payable 
9is liable in a civil action for an amount not to exceed 4 times 
10the amount assessed and not paid. The action shall be brought 
11by the Attorney General at the request of the Agency. If the 
12action involves a fixed facility in Illinois, the action shall 
13be brought in the Circuit Court of the county in which the 
14facility is located. If the action does not involve a fixed 
15facility in Illinois, the action shall be brought in the 
16Circuit Court of Sangamon County.
17(Source: P.A. 97-195, eff. 7-25-11.)
 
18    (420 ILCS 5/6.5 new)
19    Sec. 6.5. Rulemaking. The Agency is authorized to adopt 
20rules as appropriate to implement any provision of this Act 
21not otherwise specified.
 
22    (420 ILCS 5/8)  (from Ch. 111 1/2, par. 4308)
23    Sec. 8. (a) The Illinois Nuclear Safety Preparedness 
24Program shall consist of an assessment of the potential 
 
 
10400SB0025ham004- 972 -LRB104 16098 AAS 29398 a

1nuclear accidents, their radiological consequences, and the 
2necessary protective actions required to mitigate the effects 
3of such accidents. It shall include, but not necessarily be 
4limited to:
5        (1) Development of a remote effluent monitoring system 
6    capable of reliably detecting and quantifying accidental 
7    radioactive releases from nuclear power plants to the 
8    environment;
9        (2) Development of an environmental monitoring program 
10    for nuclear facilities other than nuclear power plants;
11        (3) Development of procedures for radiological 
12    assessment and radiation exposure control for areas 
13    surrounding each nuclear facility in Illinois;
14        (4) Radiological training of State and local emergency 
15    response personnel in accordance with the Agency's 
16    responsibilities under the program;
17        (5) Participation in the development of accident 
18    scenarios and in the exercising of fixed facility nuclear 
19    emergency response plans;
20        (6) Development of mitigative emergency planning 
21    standards including, but not limited to, standards 
22    pertaining to evacuations, re-entry into evacuated areas, 
23    contaminated foodstuffs and contaminated water supplies;
24        (7) Provision of specialized response equipment 
25    necessary to accomplish this task;
26        (8) Implementation of the Boiler and Pressure Vessel 
 
 
10400SB0025ham004- 973 -LRB104 16098 AAS 29398 a

1    Safety program at nuclear steam-generating facilities as 
2    mandated by Section 2005-35 of the Department of Nuclear 
3    Safety Law, or its successor statute;
4        (9) Development and implementation of a plan for 
5    inspecting and escorting all shipments of spent nuclear 
6    fuel, high-level radioactive waste, transuranic waste, and 
7    highway route controlled quantities of radioactive 
8    materials in Illinois;
9        (10) Implementation of the program under the Illinois 
10    Nuclear Facility Safety Act; and
11        (11) Development and implementation of a 
12    radiochemistry laboratory capable of preparing 
13    environmental samples, performing analyses, 
14    quantification, and reporting for assessment and radiation 
15    exposure control due to accidental radioactive releases 
16    from nuclear power plants into the environment. 
17    (b) The Agency may incorporate data collected by the 
18operator of a nuclear facility into the Agency's remote 
19monitoring system.
20    (c) The owners of each nuclear power reactor in Illinois 
21shall provide the Agency all system status signals which 
22initiate Emergency Action Level Declarations, actuate accident 
23mitigation and provide mitigation verification as directed by 
24the Agency. The Agency shall designate by rule those system 
25status signals that must be provided. Signals providing 
26indication of operating power level shall also be provided. 
 
 
10400SB0025ham004- 974 -LRB104 16098 AAS 29398 a

1The owners of the nuclear power reactors shall, at their 
2expense, ensure that valid signals will be provided 
3continuously 24 hours a day.
4    All such signals shall be provided in a manner and at a 
5frequency specified by the Agency for incorporation into and 
6augmentation of the remote effluent monitoring system 
7specified in paragraph (1) of subsection (a) of this Section. 
8Provision shall be made for assuring that such system status 
9and power level signals shall be available to the Agency 
10during reactor operation as well as throughout accidents and 
11subsequent recovery operations.
12    For nuclear reactors with operating licenses issued by the 
13Nuclear Regulatory Commission prior to the effective date of 
14this amendatory Act, such system status and power level 
15signals shall be provided to the Department of Nuclear Safety 
16(of which the Agency is the successor) by March 1, 1985. For 
17reactors without such a license on the effective date of this 
18amendatory Act, such signals shall be provided to the 
19Department prior to commencing initial fuel load for such 
20reactor. Nuclear reactors receiving their operating license 
21after September 7, 1984 (the effective date of Public Act 
2283-1342), but before July 1, 1985, shall provide such system 
23status and power level signals to the Department of Nuclear 
24Safety (of which the Agency is the successor) by September 1, 
251985.
26(Source: P.A. 102-133, eff. 7-23-21; 103-154, eff. 6-30-23.)
 
 
 
10400SB0025ham004- 975 -LRB104 16098 AAS 29398 a

1    (420 ILCS 5/9)  (from Ch. 111 1/2, par. 4309)
2    Sec. 9. Any equipment purchased by the Agency to be 
3installed on the premises of a nuclear facility pursuant to 
4the provisions of subsections (1), (2) and (7) of Section 8 of 
5this Act shall be installed by the owner of such nuclear 
6facility in accordance with criteria and standards established 
7by the Director of the Agency, including criteria for 
8location, supporting utilities, and methods of installation. 
9Such installation shall be at no cost to the Agency. The owner 
10of the nuclear facility shall also, at its expense, pay for 
11modifications of its facility as requested by the Agency    
12Department to accommodate the Agency's equipment including 
13updated equipment, and to accommodate changes in the Agency's 
14criteria and standards.
15(Source: P.A. 93-1029, eff. 8-25-04.)
 
16    (420 ILCS 5/2.5 rep.)
17    Section 90-60. The Illinois Nuclear Safety Preparedness 
18Act is amended by repealing Section 2.5.
 
19    Section 90-65. The Illinois Nuclear Facility Safety Act is 
20amended by changing Sections 3.5, 5, and 7 as follows:
 
21    (420 ILCS 10/3.5)
22    Sec. 3.5. Definitions. In this Act:
 
 
10400SB0025ham004- 976 -LRB104 16098 AAS 29398 a

1    "Agency" "IEMA-OHS" means the Illinois Emergency 
2Management Agency and Office of Homeland Security, or its 
3successor agency.
4    "Director" means the Director of IEMA-OHS.    
5    "Nuclear facilities" means nuclear power plants, 
6facilities housing nuclear test and research reactors, 
7facilities for the chemical conversion of uranium, and 
8facilities for the storage of spent nuclear fuel or high-level 
9radioactive waste.
10    "Nuclear power plant" or "nuclear steam-generating 
11facility" means a thermal power plant in which the energy 
12(heat) released by the fissioning of nuclear fuel is used to 
13boil water to produce steam.
14    "Nuclear power reactor" means an apparatus, other than an 
15atomic weapon, designed or used to sustain nuclear fission in 
16a self-supporting chain reaction.
17    "Small modular reactor" or "SMR" means an advanced nuclear 
18reactor: (1) with a rated nameplate capacity of 300 electrical 
19megawatts or less; and (2) that may be constructed and 
20operated in combination with similar reactors at a single 
21site.
22(Source: P.A. 103-569, eff. 6-1-24.)
 
23    (420 ILCS 10/5)  (from Ch. 111 1/2, par. 4355)
24    Sec. 5. Program for Illinois nuclear power plant 
25inspectors. 
 
 
10400SB0025ham004- 977 -LRB104 16098 AAS 29398 a

1    (a) Consistent with federal law and policy statements of 
2and cooperative agreements with the Nuclear Regulatory 
3Commission with respect to State participation in health and 
4safety regulation of nuclear facilities, and in recognition of 
5the role provided for the states by such laws, policy 
6statements and cooperative agreements, the Agency shall 
7develop and implement a program for Illinois resident    
8inspectors that, when fully implemented, shall provide for one 
9full-time Agency Illinois resident inspector for at each 
10nuclear power plant in Illinois. The owner of each of the 
11nuclear power plants to which they are assigned shall provide, 
12at its expense, office space and equipment reasonably required 
13by the resident inspectors while they are on the premises of 
14the nuclear power plants. The Illinois resident inspectors 
15shall operate in accordance with a cooperative agreement 
16executed by the Agency and the Nuclear Regulatory Commission 
17and shall have access to the nuclear power plants to which they 
18have been assigned in accordance with that agreement; 
19provided, however, that the Illinois resident inspectors shall 
20have no greater access than is afforded to an a resident    
21inspector of the Nuclear Regulatory Commission.
22    (b) The Agency may also inspect licensed nuclear power 
23plants that have permanently ceased operations. The 
24inspections shall be performed by inspectors qualified as 
25Illinois resident inspectors. The inspectors need not be 
26resident at nuclear power plants that have permanently ceased 
 
 
10400SB0025ham004- 978 -LRB104 16098 AAS 29398 a

1operations. The inspectors shall conduct inspections in 
2accordance with a cooperative agreement executed by the Agency 
3and the Nuclear Regulatory Commission and shall have access to 
4the nuclear power plants that have permanently ceased 
5operations; provided, however, that the Illinois inspectors 
6shall have no greater access than is afforded to inspectors of 
7the Nuclear Regulatory Commission. The owner of each of the 
8nuclear power plants that has permanently ceased operations 
9shall provide, at its expense, office space and equipment 
10reasonably required by the inspectors while they are on the 
11premises of the nuclear power plants.
12    (c) The Illinois resident inspectors and inspectors 
13assigned under subsection (b) shall each operate in accordance 
14with the security plan for the nuclear power plant to which 
15they are assigned, but in no event shall they be required to 
16meet any requirements imposed by a nuclear power plant owner 
17that are not imposed on resident inspectors and inspectors of 
18the Nuclear Regulatory Commission. The Agency programs and 
19activities under this Section shall not be inconsistent with 
20federal law.
21(Source: P.A. 95-777, eff. 8-4-08.)
 
22    (420 ILCS 10/7)  (from Ch. 111 1/2, par. 4357)
23    Sec. 7. The Agency shall not engage in any program of 
24Illinois resident inspectors or inspectors assigned under 
25subsection (b) of Section 5 at any nuclear power plant in 
 
 
10400SB0025ham004- 979 -LRB104 16098 AAS 29398 a

1Illinois except as specifically directed by law.
2(Source: P.A. 95-777, eff. 8-4-08.)
 
3    Section 90-70. The Illinois Low-Level Radioactive Waste 
4Management Act is amended by changing Sections 3, 13, 14, 15, 
517, and 21 as follows:
 
6    (420 ILCS 20/3)  (from Ch. 111 1/2, par. 241-3)
7    Sec. 3. Definitions. As used in this Act:    
8    "Agency" or "IEMA-OHS" means the Illinois Emergency 
9Management Agency and Office of Homeland Security, or its 
10successor agency. 
11    "Broker" means any person who takes possession of 
12low-level waste for purposes of consolidation and shipment.
13    "Compact" means the Central Midwest Interstate Low-Level 
14Radioactive Waste Compact.
15    "Decommissioning" means the measures taken at the end of a 
16facility's operating life to assure the continued protection 
17of the public from any residual radioactivity or other 
18potential hazards present at a facility.
19    "Director" means the Director of the Agency.
20    "Disposal" means the isolation of waste from the biosphere 
21in a permanent facility designed for that purpose.
22    "Facility" means a parcel of land or site, together with 
23structures, equipment and improvements on or appurtenant to 
24the land or site, which is used or is being developed for the 
 
 
10400SB0025ham004- 980 -LRB104 16098 AAS 29398 a

1treatment, storage or disposal of low-level radioactive waste. 
2"Facility" does not include lands, sites, structures, or 
3equipment used by a generator in the generation of low-level 
4radioactive wastes.
5    "Generator" means any person who produces or possesses 
6low-level radioactive waste in the course of or incident to 
7manufacturing, power generation, processing, medical diagnosis 
8and treatment, research, education, or other activity.
9    "Hazardous waste" means a waste, or combination of wastes, 
10which because of its quantity, concentration, or physical, 
11chemical, or infectious characteristics may cause or 
12significantly contribute to an increase in mortality or an 
13increase in serious, irreversible, or incapacitating 
14reversible, illness; or pose a substantial present or 
15potential hazard to human health or the environment when 
16improperly treated, stored, transported, or disposed of, or 
17otherwise managed, and which has been identified, by 
18characteristics or listing, as hazardous under Section 3001 of 
19the Resource Conservation and Recovery Act of 1976, P.L. 
2094-580 or under regulations of the Pollution Control Board.
21    "High-level radioactive waste" means:
22        (1) the highly radioactive material resulting from the 
23    reprocessing of spent nuclear fuel including liquid waste 
24    produced directly in reprocessing and any solid material 
25    derived from the liquid waste that contains fission 
26    products in sufficient concentrations; and
 
 
10400SB0025ham004- 981 -LRB104 16098 AAS 29398 a

1        (2) the highly radioactive material that the Nuclear 
2    Regulatory Commission has determined, on the effective 
3    date of this Amendatory Act of 1988, to be high-level 
4    radioactive waste requiring permanent isolation.
5    "Low-level radioactive waste" or "waste" means radioactive 
6waste not classified as (1) high-level radioactive waste, (2) 
7transuranic waste, (3) spent nuclear fuel, or (4) byproduct 
8material as defined in Sections 11e(2), 11e(3), and 11e(4) of 
9the Atomic Energy Act of 1954 (42 U.S.C. 2014). This 
10definition shall apply notwithstanding any declaration by the 
11federal government, a state, or any regulatory agency that any 
12radioactive material is exempt from any regulatory control. 
13    "Mixed waste" means waste that is both "hazardous waste" 
14and "low-level radioactive waste" as defined in this Act.
15    "Nuclear facilities" means nuclear power plants, 
16facilities housing nuclear test and research reactors, 
17facilities for the chemical conversion of uranium, and 
18facilities for the storage of spent nuclear fuel or high-level 
19radioactive waste.
20    "Nuclear power plant" or "nuclear steam-generating 
21facility" means a thermal power plant in which the energy 
22(heat) released by the fissioning of nuclear fuel is used to 
23boil water to produce steam.
24    "Nuclear power reactor" means an apparatus, other than an 
25atomic weapon, designed or used to sustain nuclear fission in 
26a self-supporting chain reaction.    
 
 
10400SB0025ham004- 982 -LRB104 16098 AAS 29398 a

1    "Person" means an individual, corporation, business 
2enterprise, or other legal entity either public or private and 
3any legal successor, representative, agent, or agency of that 
4individual, corporation, business enterprise, or legal entity.
5    "Post-closure care" means the continued monitoring of the 
6regional disposal facility after closure for the purposes of 
7detecting a need for maintenance, ensuring environmental 
8safety, and determining compliance with applicable licensure 
9and regulatory requirements, and includes undertaking any 
10remedial actions necessary to protect public health and the 
11environment from radioactive releases from the facility.
12    "Regional disposal facility" or "disposal facility" means 
13the facility established by the State of Illinois under this 
14Act for disposal away from the point of generation of waste 
15generated in the region of the Compact.
16    "Release" means any spilling, leaking, pumping, pouring, 
17emitting, emptying, discharging, injecting, escaping, 
18leaching, dumping, or disposing into the environment of 
19low-level radioactive waste.
20    "Remedial action" means those actions taken in the event 
21of a release or threatened release of low-level radioactive 
22waste into the environment, to prevent or minimize the release 
23of the waste so that it does not migrate to cause substantial 
24danger to present or future public health or welfare or the 
25environment. The term includes, but is not limited to, actions 
26at the location of the release such as storage, confinement, 
 
 
10400SB0025ham004- 983 -LRB104 16098 AAS 29398 a

1perimeter protection using dikes, trenches or ditches, clay 
2cover, neutralization, cleanup of released low-level 
3radioactive wastes, recycling or reuse, dredging or 
4excavations, repair or replacement of leaking containers, 
5collection of leachate and runoff, onsite treatment or 
6incineration, provision of alternative water supplies, and any 
7monitoring reasonably required to assure that these actions 
8protect human health and the environment.
9    "Scientific Surveys" means, collectively, the Illinois 
10State Geological Survey and the Illinois State Water Survey of 
11the University of Illinois.
12    "Shallow land burial" means a land disposal facility in 
13which radioactive waste is disposed of in or within the upper 
1430 meters of the earth's surface. However, this definition 
15shall not include an enclosed, engineered, structurally 
16re-enforced and solidified bunker that extends below the 
17earth's surface.
18    "Small modular reactor" or "SMR" means an advanced nuclear 
19reactor: (1) with a rated nameplate capacity of 300 electrical 
20megawatts or less; and (2) that may be constructed and 
21operated in combination with similar reactors at a single 
22site.
23    "Storage" means the temporary holding of waste for 
24treatment or disposal for a period determined by Agency 
25regulations.
26    "Treatment" means any method, technique, or process, 
 
 
10400SB0025ham004- 984 -LRB104 16098 AAS 29398 a

1including storage for radioactive decay, designed to change 
2the physical, chemical, or biological characteristics or 
3composition of any waste in order to render the waste safer for 
4transport, storage, or disposal, amenable to recovery, 
5convertible to another usable material, or reduced in volume.
6    "Waste management" means the storage, transportation, 
7treatment, or disposal of waste.
8(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24; 
9revised 7-30-24.)
 
10    (420 ILCS 20/13)  (from Ch. 111 1/2, par. 241-13)
11    Sec. 13. Waste fees. 
12    (a) The Agency shall collect a fee from each generator of 
13low-level radioactive wastes in this State, except for units 
14of local government as otherwise provided in this subsection. 
15Except as provided in subsection (b) subdivision (b)(2) and 
16subsections (c) and (d), the amount of the fee shall be $100    
17$50.00 or the following amount, whichever is greater:
18        (1) $1 per cubic foot of waste shipped for storage, 
19    treatment or disposal if storage of the waste for shipment 
20    occurred prior to September 7, 1984;
21        (2) $2 per cubic foot of waste stored for shipment if 
22    storage of the waste occurs on or after September 7, 1984, 
23    but prior to October 1, 1985;
24        (1) (3) $3 per cubic foot of waste stored for shipment 
25    if storage of the waste occurs on or after October 1, 1985; 
 
 
10400SB0025ham004- 985 -LRB104 16098 AAS 29398 a

1    and    
2        (4) $2 per cubic foot of waste shipped for storage, 
3    treatment or disposal if storage of the waste for shipment 
4    occurs on or after September 7, 1984 but prior to October 
5    1, 1985, provided that no fee has been collected 
6    previously for storage of the waste;
7        (2) (5) $3 per cubic foot of waste shipped for 
8    storage, treatment, or disposal if storage of the waste 
9    for shipment occurs on or after October 1, 1985, provided 
10    that no fees have been collected previously for storage of 
11    the waste.
12    All fees collected under this subsection Such fees shall 
13be collected annually or as determined by the Agency and shall 
14be deposited into in the fund low-level radioactive waste 
15funds as provided in Section 14 of this Act. Notwithstanding 
16any other provision of this Act, no fee under this Section 
17shall be collected from a generator for waste generated 
18incident to manufacturing before December 31, 1980, and 
19shipped for disposal outside of this State before December 31, 
201992, as part of a site reclamation leading to license 
21termination.
22    Units of local government are exempt from the fee 
23provisions of this subsection.    
24    (b) The owner of any nuclear power reactor that has a 
25license issued by the Nuclear Regulatory Commission for any 
26portion of a State fiscal year shall pay an annual fee in 
 
 
10400SB0025ham004- 986 -LRB104 16098 AAS 29398 a

1accordance with subsection (a) or $30,000 per nuclear power 
2reactor, whichever is less. The fee shall be paid by July 1 of 
3each State fiscal year. All moneys collected under this 
4subsection shall be deposited pursuant to Section 14 and 
5expended, subject to appropriation, for the purposes provided 
6in Section 14. (1) Small modular reactors shall pay low-level 
7radioactive waste fees in accordance with subsection (a).    
8    (2) Each nuclear power reactor in this State for which an 
9operating license has been issued by the Nuclear Regulatory 
10Commission shall not be subject to the fee required by 
11subsection (a) with respect to (1) waste stored for shipment 
12if storage of the waste occurs on or after January 1, 1986; and 
13(2) waste shipped for storage, treatment or disposal if 
14storage of the waste for shipment occurs on or after January 1, 
151986. In lieu of the fee, each reactor shall be required to pay 
16an annual fee as provided in this subsection for the 
17treatment, storage and disposal of low-level radioactive 
18waste. Beginning with State fiscal year 1986 and through State 
19fiscal year 1997, fees shall be due and payable on January 1st 
20of each year. For State fiscal year 1998 and all subsequent 
21State fiscal years, fees shall be due and payable on July 1 of 
22each fiscal year. The fee due on July 1, 1997 shall be payable 
23on that date, or within 10 days after the effective date of 
24this amendatory Act of 1997, whichever is later.
25    The owner of any nuclear power reactor that has an 
26operating license issued by the Nuclear Regulatory Commission 
 
 
10400SB0025ham004- 987 -LRB104 16098 AAS 29398 a

1for any portion of State fiscal year 1998 shall continue to pay 
2an annual fee of $90,000 for the treatment, storage, and 
3disposal of low-level radioactive waste through State fiscal 
4year 2002. The fee shall be due and payable on July 1 of each 
5fiscal year. The fee due on July 1, 1998 shall be payable on 
6that date, or within 10 days after the effective date of this 
7amendatory Act of 1998, whichever is later. If the balance in 
8the Low-Level Radioactive Waste Facility Operation Fund    
9Low-Level Radioactive Waste Facility Development and Operation 
10Fund falls below $500,000, at as of the end of any fiscal year 
11after fiscal year 2002, the Agency is authorized to assess by 
12rule, after notice and a hearing, an additional annual fee to 
13be paid by the owners of nuclear power reactors for which 
14operating licenses have been issued by the Nuclear Regulatory 
15Commission, except that no additional annual fee shall be 
16assessed because of the fund balance at the end of fiscal year 
172005 or the end of fiscal year 2006. The additional annual fee 
18shall be payable on the date or dates specified by rule and 
19shall not exceed $30,000 per nuclear power operating reactor 
20per year.
21    (c) (Blank). In each of State fiscal years 1988, 1989 and 
221990, in addition to the fee imposed in subsections (b) and 
23(d), the owner of each nuclear power reactor in this State for 
24which an operating license has been issued by the Nuclear 
25Regulatory Commission shall pay a fee of $408,000. If an 
26operating license is issued during one of those 3 fiscal 
 
 
10400SB0025ham004- 988 -LRB104 16098 AAS 29398 a

1years, the owner shall pay a prorated amount of the fee equal 
2to $1,117.80 multiplied by the number of days in the fiscal 
3year during which the nuclear power reactor was licensed.
4    The fee shall be due and payable as follows: in fiscal year 
51988, $204,000 shall be paid on October 1, 1987 and $102,000 
6shall be paid on each of January 1, 1988 and April 1, 1988; in 
7fiscal year 1989, $102,000 shall be paid on each of July 1, 
81988, October 1, 1988, January 1, 1989 and April 1, 1989; and 
9in fiscal year 1990, $102,000 shall be paid on each of July 1, 
101989, October 1, 1989, January 1, 1990 and April 1, 1990. If 
11the operating license is issued during one of the 3 fiscal 
12years, the owner shall be subject to those payment dates, and 
13their corresponding amounts, on which the owner possesses an 
14operating license and, on June 30 of the fiscal year of 
15issuance of the license, whatever amount of the prorated fee 
16remains outstanding.
17    All of the amounts collected by the Agency under this 
18subsection (c) shall be deposited into the Low-Level 
19Radioactive Waste Facility Development and Operation Fund 
20created under subsection (a) of Section 14 of this Act and 
21expended, subject to appropriation, for the purposes provided 
22in that subsection.
23    (d) (Blank). In addition to the fees imposed in 
24subsections (b) and (c), the owners of nuclear power reactors 
25in this State for which operating licenses have been issued by 
26the Nuclear Regulatory Commission shall pay the following fees 
 
 
10400SB0025ham004- 989 -LRB104 16098 AAS 29398 a

1for each such nuclear power reactor: for State fiscal year 
21989, $325,000 payable on October 1, 1988, $162,500 payable on 
3January 1, 1989, and $162,500 payable on April 1, 1989; for 
4State fiscal year 1990, $162,500 payable on July 1, $300,000 
5payable on October 1, $300,000 payable on January 1 and 
6$300,000 payable on April 1; for State fiscal year 1991, 
7either (1) $150,000 payable on July 1, $650,000 payable on 
8September 1, $675,000 payable on January 1, and $275,000 
9payable on April 1, or (2) $150,000 on July 1, $130,000 on the 
10first day of each month from August through December, $225,000 
11on the first day of each month from January through March and 
12$92,000 on the first day of each month from April through June; 
13for State fiscal year 1992, $260,000 payable on July 1, 
14$900,000 payable on September 1, $300,000 payable on October 
151, $150,000 payable on January 1, and $100,000 payable on 
16April 1; for State fiscal year 1993, $100,000 payable on July 
171, $230,000 payable on August 1 or within 10 days after July 
1831, 1992, whichever is later, and $355,000 payable on October 
191; for State fiscal year 1994, $100,000 payable on July 1, 
20$75,000 payable on October 1 and $75,000 payable on April 1; 
21for State fiscal year 1995, $100,000 payable on July 1, 
22$75,000 payable on October 1, and $75,000 payable on April 1, 
23for State fiscal year 1996, $100,000 payable on July 1, 
24$75,000 payable on October 1, and $75,000 payable on April 1. 
25The owner of any nuclear power reactor that has an operating 
26license issued by the Nuclear Regulatory Commission for any 
 
 
10400SB0025ham004- 990 -LRB104 16098 AAS 29398 a

1portion of State fiscal year 1998 shall pay an annual fee of 
2$30,000 through State fiscal year 2003. For State fiscal year 
32004 and subsequent fiscal years, the owner of any nuclear 
4power reactor that has an operating license issued by the 
5Nuclear Regulatory Commission shall pay an annual fee of 
6$30,000 per reactor, provided that the fee shall not apply to a 
7nuclear power reactor with regard to which the owner notified 
8the Nuclear Regulatory Commission during State fiscal year 
91998 that the nuclear power reactor permanently ceased 
10operations. The fee shall be due and payable on July 1 of each 
11fiscal year. The fee due on July 1, 1998 shall be payable on 
12that date, or within 10 days after the effective date of this 
13amendatory Act of 1998, whichever is later. The fee due on July 
141, 1997 shall be payable on that date or within 10 days after 
15the effective date of this amendatory Act of 1997, whichever 
16is later. If the payments under this subsection for fiscal 
17year 1993 due on January 1, 1993, or on April 1, 1993, or both, 
18were due before the effective date of this amendatory Act of 
19the 87th General Assembly, then those payments are waived and 
20need not be made.
21    All of the amounts collected by the Agency under this 
22subsection (d) shall be deposited into the Low-Level 
23Radioactive Waste Facility Development and Operation Fund 
24created pursuant to subsection (a) of Section 14 of this Act 
25and expended, subject to appropriation, for the purposes 
26provided in that subsection.
 
 
10400SB0025ham004- 991 -LRB104 16098 AAS 29398 a

1    All payments made by licensees under this subsection (d) 
2for fiscal year 1992 that are not appropriated and obligated 
3by the Agency above $1,750,000 per reactor in fiscal year 
41992, shall be credited to the licensees making the payments 
5to reduce the per reactor fees required under this subsection 
6(d) for fiscal year 1993.
7    (e) (Blank). The Agency shall promulgate rules and 
8regulations establishing standards for the collection of the 
9fees authorized by this Section. The regulations shall 
10include, but need not be limited to:
11        (1) the records necessary to identify the amounts of 
12    low-level radioactive wastes produced;
13        (2) the form and submission of reports to accompany 
14    the payment of fees to the Agency; and
15        (3) the time and manner of payment of fees to the 
16    Agency, which payments shall not be more frequent than 
17    quarterly.
18    (f) Any operating agreement entered into under subsection 
19(b) of Section 5 of this Act between the Agency and any 
20disposal facility contractor shall, subject to the provisions 
21of this Act, authorize the contractor to impose upon and 
22collect from persons using the disposal facility fees designed 
23and set at levels reasonably calculated to produce sufficient 
24revenues (1) to pay all costs and expenses properly incurred 
25or accrued in connection with, and properly allocated to, 
26performance of the contractor's obligations under the 
 
 
10400SB0025ham004- 992 -LRB104 16098 AAS 29398 a

1operating agreement, and (2) to provide reasonable and 
2appropriate compensation or profit to the contractor under the 
3operating agreement. For purposes of this subsection (f), the 
4term "costs and expenses" may include, without limitation, (i) 
5direct and indirect costs and expenses for labor, services, 
6equipment, materials, insurance and other risk management 
7costs, interest and other financing charges, and taxes or fees 
8in lieu of taxes; (ii) payments to or required by the United 
9States, the State of Illinois or any agency or department 
10thereof, the Central Midwest Interstate Low-Level Radioactive 
11Waste Compact, and subject to the provisions of this Act, any 
12unit of local government; (iii) amortization of capitalized 
13costs with respect to the disposal facility and its 
14development, including any capitalized reserves; and (iv) 
15payments with respect to reserves, accounts, escrows or trust 
16funds required by law or otherwise provided for under the 
17operating agreement.    
18    (g) (Blank).
19    (h) (Blank).
20    (i) (Blank).
21    (j) (Blank).
22    (j-5) Prior to commencement of facility operations, the 
23Agency shall adopt rules providing for the establishment and 
24collection of fees and charges with respect to the use of the 
25disposal facility as provided in subsection (f) of this 
26Section.
 
 
10400SB0025ham004- 993 -LRB104 16098 AAS 29398 a

1    (k) The regional disposal facility shall be subject to ad 
2valorem real estate taxes lawfully imposed by units of local 
3government and school districts with jurisdiction over the 
4facility. No other local government tax, surtax, fee or other 
5charge on activities at the regional disposal facility shall 
6be allowed except as authorized by the Agency.
7    (l) The Agency shall have the power, in the event that 
8acceptance of waste for disposal at the regional disposal 
9facility is suspended, delayed or interrupted, to impose 
10emergency fees on the generators of low-level radioactive 
11waste. Generators shall pay emergency fees within 30 days of 
12receipt of notice of the emergency fees. The Agency Department    
13shall deposit all of the receipts of any fees collected under 
14this subsection into the Low-Level Radioactive Waste Facility 
15Operation Fund Low-Level Radioactive Waste Facility 
16Development and Operation Fund created under subsection (b) of 
17Section 14. Emergency fees may be used to mitigate the impacts 
18of the suspension or interruption of acceptance of waste for 
19disposal. The requirements for rulemaking in the Illinois 
20Administrative Procedure Act shall not apply to the imposition 
21of emergency fees under this subsection.
22    (m) The Agency shall adopt promulgate any other rules and 
23regulations as may be necessary to implement this Section.
24(Source: P.A. 103-569, eff. 6-1-24.)
 
25    (420 ILCS 20/14)  (from Ch. 111 1/2, par. 241-14)
 
 
10400SB0025ham004- 994 -LRB104 16098 AAS 29398 a

1    Sec. 14. Waste management funds. 
2    (a) There is hereby created in the State Treasury a 
3special fund to be known as the Low-Level Radioactive Waste 
4Facility Operation Fund Low-Level Radioactive Waste Facility 
5Development and Operation Fund. All monies within the 
6Low-Level Radioactive Waste Facility Operation Fund Low-Level 
7Radioactive Waste Facility Development and Operation Fund    
8shall be invested by the State Treasurer in accordance with 
9established investment practices. Interest earned by such 
10investment shall be returned to the Low-Level Radioactive 
11Waste Facility Operation Fund Low-Level Radioactive Waste 
12Facility Development and Operation Fund. The Agency shall 
13deposit all receipts from the fees required under subsections 
14(a) and (b) of Section 13 in the State Treasury to the credit 
15of this Fund. Subject to appropriation, the Agency is 
16authorized to expend all moneys in the Fund in amounts it deems 
17necessary for:
18        (1) hiring personnel and any other operating and 
19    contingent expenses necessary for the proper 
20    administration of this Act;
21        (2) contracting with any firm for the purpose of 
22    carrying out the purposes of this Act;
23        (3) grants to the Central Midwest Interstate Low-Level 
24    Radioactive Waste Commission;
25        (4) hiring personnel, contracting with any person, and 
26    meeting any other expenses incurred by the Agency in 
 
 
10400SB0025ham004- 995 -LRB104 16098 AAS 29398 a

1    fulfilling its responsibilities under the Radioactive 
2    Waste Compact Enforcement Act;
3        (5) activities under Sections 10, 10.2 and 10.3;
4        (6) payment of fees in lieu of taxes to a local 
5    government having within its boundaries a regional 
6    disposal facility;
7        (7) payment of grants to counties or municipalities 
8    under Section 12.1; and
9        (8) fulfillment of obligations under a community 
10    agreement under Section 12.1;
11        (9) decommissioning and other procedures required for 
12    the proper closure of a regional disposal facility;    
13        (10) monitoring, inspecting, and other procedures 
14    required for the proper closure, decommissioning, and 
15    post-closure care of a regional disposal facility;    
16        (11) taking any remedial actions necessary to protect 
17    human health and the environment from releases or 
18    threatened releases of wastes from a regional disposal 
19    facility;    
20        (12) the purchase of facility and third-party 
21    liability insurance necessary during the institutional 
22    control period of a regional disposal facility;    
23        (13) mitigating the impacts of the suspension or 
24    interruption of the acceptance of waste for disposal; and    
25        (14) compensating any person suffering any damages or 
26    losses to a person or property caused by a release from the 
 
 
10400SB0025ham004- 996 -LRB104 16098 AAS 29398 a

1    regional disposal facility as provided for in Section 15.
2    In spending monies pursuant to such appropriations, the 
3Agency shall to the extent practicable avoid duplicating 
4expenditures made by any firm pursuant to a contract awarded 
5under this Section.
6    (b) There is hereby created in the State Treasury a 
7special fund to be known as the Low-Level Radioactive Waste 
8Facility Closure, Post-Closure Care and Compensation Fund. All 
9monies within the Low-Level Radioactive Waste Facility 
10Closure, Post-Closure Care and Compensation Fund shall be 
11invested by the State Treasurer in accordance with established 
12investment practices. Interest earned by such investment shall 
13be returned to the Low-Level Radioactive Waste Facility 
14Closure, Post-Closure Care and Compensation Fund. All deposits 
15into this Fund shall be held by the State Treasurer separate 
16and apart from all public money or funds of this State. Subject 
17to appropriation, the Agency is authorized to expend any 
18moneys in this Fund in amounts it deems necessary for:
19        (1) decommissioning and other procedures required for 
20    the proper closure of the regional disposal facility;
21        (2) monitoring, inspecting, and other procedures 
22    required for the proper closure, decommissioning, and 
23    post-closure care of the regional disposal facility;
24        (3) taking any remedial actions necessary to protect 
25    human health and the environment from releases or 
26    threatened releases of wastes from the regional disposal 
 
 
10400SB0025ham004- 997 -LRB104 16098 AAS 29398 a

1    facility;
2        (4) the purchase of facility and third-party liability 
3    insurance necessary during the institutional control 
4    period of the regional disposal facility;
5        (5) mitigating the impacts of the suspension or 
6    interruption of the acceptance of waste for disposal;
7        (6) compensating any person suffering any damages or 
8    losses to a person or property caused by a release from the 
9    regional disposal facility as provided for in Section 15; 
10    and
11        (7) fulfillment of obligations under a community 
12    agreement under Section 12.1.
13    On or before March 1 of each year through March 1, 2025, 
14the Agency shall deliver to the Governor, the President and 
15Minority Leader of the Senate, the Speaker and Minority Leader 
16of the House, and each of the generators that have contributed 
17during the preceding State fiscal year to the Fund a financial 
18statement, certified and verified by the Director, which 
19details all receipts and expenditures from the Fund during the 
20preceding State fiscal year. The financial statements shall 
21identify all sources of income to the Fund and all recipients 
22of expenditures from the Fund, shall specify the amounts of 
23all the income and expenditures, and shall indicate the 
24amounts of all the income and expenditures, and shall indicate 
25the purpose for all expenditures.
26    On July 1, 2025, or as soon thereafter as practical, the 
 
 
10400SB0025ham004- 998 -LRB104 16098 AAS 29398 a

1State Comptroller shall direct and the State Treasurer shall 
2transfer the remaining balance from the Low-Level Radioactive 
3Waste Facility Closure, Post-Closure Care and Compensation 
4Fund into the Low-Level Radioactive Waste Facility Operation 
5Fund Low-Level Radioactive Waste Facility Development and 
6Operation Fund. Upon completion of the transfer, the Low-Level 
7Radioactive Waste Facility Closure, Post-Closure Care and 
8Compensation Fund is dissolved, and any future deposits due to 
9that Fund and any outstanding obligations or liabilities of 
10that Fund shall pass to the Low-Level Radioactive Waste 
11Facility Development and Operation Fund. 
12    (c) (Blank).
13    (d) The Agency may accept for any of its purposes and 
14functions any donations, grants of money, equipment, supplies, 
15materials, and services from any state or the United States, 
16or from any institution, person, firm or corporation. Any 
17donation or grant of money shall be deposited into the 
18Low-Level Radioactive Waste Facility Operation Fund Low-Level 
19Radioactive Waste Facility Development and Operation Fund.
20(Source: P.A. 104-2, eff. 6-16-25.)
 
21    (420 ILCS 20/15)  (from Ch. 111 1/2, par. 241-15)
22    Sec. 15. Compensation. 
23    (a) Any person may apply to the Agency pursuant to this 
24Section for compensation of a loss caused by the release, in 
25Illinois, of radioactivity from the regional disposal 
 
 
10400SB0025ham004- 999 -LRB104 16098 AAS 29398 a

1facility. The Agency shall prescribe appropriate forms and 
2procedures for claims filed pursuant to this Section, which 
3shall include, as a minimum, the following:    
4        (1) Provisions requiring the claimant to make a sworn 
5    verification of the claim to the best of his or her 
6    knowledge.    
7        (2) A full description, supported by appropriate 
8    evidence from government agencies, of the release of the 
9    radioactivity claimed to be the cause of the physical 
10    injury, illness, loss of income or property damage.    
11        (3) If making a claim based upon physical injury or 
12    illness, certification of the medical history of the 
13    claimant for the 5 years preceding the date of the claim, 
14    along with certification of the alleged physical injury or 
15    illness, and expenses for the physical injury or illness, 
16    made by hospitals, physicians or other qualified medical 
17    authorities.    
18        (4) If making a claim for lost income, information on 
19    the claimant's income as reported on his or her federal 
20    income tax return or other document for the preceding 3 
21    years in order to compute lost wages or income.
22    (b) The Agency shall hold at least one hearing, if 
23requested by the claimant, within 60 days of submission of a 
24claim to the Agency. The Director shall render a decision on a 
25claim within 30 days of the hearing unless all of the parties 
26to the claim agree in writing to an extension of time. All 
 
 
10400SB0025ham004- 1000 -LRB104 16098 AAS 29398 a

1decisions rendered by the Director shall be in writing, with 
2notification to all appropriate parties. The decision shall be 
3considered a final administrative decision for the purposes of 
4judicial review.
5    (c) The following losses shall be compensable under this 
6Section, provided that the Agency has found that the claimant 
7has established, by the weight of the evidence, that the 
8losses were proximately caused by the designated release and 
9are not otherwise compensable under law:    
10        (1) One hundred percent of uninsured, out-of-pocket 
11    medical expenses, for up to 3 years from the onset of 
12    treatment;    
13        (2) Eighty percent of any uninsured, actual lost 
14    wages, or business income in lieu of wages, caused by 
15    injury to the claimant or the claimant's property, not to 
16    exceed $15,000 per year for 3 years;    
17        (3) Eighty percent of any losses or damages to real or 
18    personal property; and    
19        (4) One hundred percent of costs of any remedial 
20    actions on such property necessary to protect human health 
21    and the environment.
22    (d) No claim may be presented to the Agency under this 
23Section later than 5 years from the date of discovery of the 
24damage or loss.
25    (e) Compensation for any damage or loss under this Section 
26shall preclude indemnification or reimbursement from any other 
 
 
10400SB0025ham004- 1001 -LRB104 16098 AAS 29398 a

1source for the identical damage or loss, and indemnification 
2or reimbursement from any other source shall preclude 
3compensation under this Section.
4    (f) The Agency shall adopt, and revise when appropriate, 
5rules and regulations necessary to implement the provisions of 
6this Section, including methods that provide for establishing 
7that a claimant has exercised reasonable diligence in 
8satisfying the conditions of the application requirements, for 
9specifying the proof necessary to establish a damage or loss 
10compensable under this Section and for establishing the 
11administrative procedures to be followed in reviewing claims.
12    (g) Claims approved by the Director shall be paid from the 
13Low-Level Radioactive Waste Facility Operation Fund Low-Level 
14Radioactive Waste Facility Development and Operation Fund, 
15except that claims shall not be paid in excess of the amount 
16available in the Fund. In the case of insufficient amounts in 
17the Fund to satisfy claims against the Fund, the General 
18Assembly may appropriate monies to the Fund in amounts it 
19deems necessary to pay the claims.
20(Source: P.A. 104-2, eff. 6-16-25.)
 
21    (420 ILCS 20/17)  (from Ch. 111 1/2, par. 241-17)
22    Sec. 17. Penalties. 
23    (a) Any person operating any facility in violation of 
24Section 8 shall be subject to a civil penalty not to exceed 
25$100,000 per day of violation.
 
 
10400SB0025ham004- 1002 -LRB104 16098 AAS 29398 a

1    (b) Any person failing to pay the fees provided for in 
2Section 13 shall be liable to a civil penalty not to exceed 4 
3times the amount of the fees not paid.
4    (c) At the request of the Agency, the civil penalties 
5shall be recovered in an action brought by the Attorney 
6General on behalf of the State in the circuit court in which 
7the violation occurred. All amounts collected from fines under 
8this Section shall be deposited into the Low-Level Radioactive 
9Waste Facility Operation Fund Low-Level Radioactive Waste 
10Facility Development and Operation Fund.
11(Source: P.A. 104-2, eff. 6-16-25.)
 
12    (420 ILCS 20/21)  (from Ch. 111 1/2, par. 241-21)
13    Sec. 21. Shared Liability. Any state which enacts the 
14Central Midwest Interstate Low-Level Radioactive Waste Compact 
15and has as its resident a generator shall be liable for the 
16cost of post-closure care in excess of funds available from 
17the Low-Level Radioactive Waste Facility Operation Fund    
18Low-Level Radioactive Waste Facility Development and Operation 
19Fund or from any liability insurance or other means of 
20establishing financial responsibility in an amount sufficient 
21to provide for any necessary corrective actions or liabilities 
22arising during the period of post-closure care. The extent of 
23such liability shall not be in excess of the prorated share of 
24the volume of waste placed in the facility by the generators of 
25each state which has enacted the Central Midwest Interstate 
 
 
10400SB0025ham004- 1003 -LRB104 16098 AAS 29398 a

1Low-Level Radioactive Waste Compact. However, this Section 
2shall not apply to a party state with a total volume of waste 
3recorded on low-level radioactive waste manifests for any year 
4that is less than 10 percent of the total volume recorded on 
5such manifests for the region during the same year.
6(Source: P.A. 104-2, eff. 6-16-25.)
 
7    Section 90-75. The Radioactive Waste Storage Act is 
8amended by changing Sections 0.05 and 1 as follows:
 
9    (420 ILCS 35/0.05)
10    Sec. 0.05. Definitions. In this Act:
11    "IEMA-OHS" means the Illinois Emergency Management Agency 
12and Office of Homeland Security, or its successor agency.
13    "Director" means the Director of IEMA-OHS. 
14    "Nuclear power plant" or "nuclear steam-generating 
15facility" means a thermal power plant in which the energy 
16(heat) released by the fissioning of nuclear fuel is used to 
17boil water to produce steam.
18    "Nuclear facilities" means nuclear power plants, 
19facilities housing nuclear test and research reactors, 
20facilities for the chemical conversion of uranium, and 
21facilities for the storage of spent nuclear fuel or high-level 
22radioactive waste.
23    "Nuclear power reactor" means an apparatus, other than an 
24atomic weapon, designed or used to sustain nuclear fission in 
 
 
10400SB0025ham004- 1004 -LRB104 16098 AAS 29398 a

1a self-supporting chain reaction.
2    "Small modular reactor" or "SMR" means an advanced nuclear 
3reactor: (1) with a rated nameplate capacity of 300 electrical 
4megawatts or less; and (2) that may be constructed and 
5operated in combination with similar reactors at a single 
6site.
7(Source: P.A. 103-569, eff. 6-1-24.)
 
8    (420 ILCS 35/1)  (from Ch. 111 1/2, par. 230.1)
9    Sec. 1. The Director is authorized to acquire by private 
10purchase, acceptance, or by condemnation in the manner 
11provided for the exercise of the power of eminent domain under 
12the Eminent Domain Act, any and all lands, buildings and 
13grounds where radioactive by-products and wastes produced by 
14industrial, medical, agricultural, scientific or other 
15organizations can be concentrated, stored or otherwise 
16disposed in a manner consistent with the public health and 
17safety. Whenever, in the judgment of the Director, it is 
18necessary to relocate existing facilities for the 
19construction, operation, closure or long-term care of a 
20facility for the safe and secure disposal of low-level 
21radioactive waste, the cost of relocating such existing 
22facilities may be deemed a part of the disposal facility land 
23acquisition and the Agency may, on behalf of the State, pay 
24such costs. Existing facilities include public utilities, 
25commercial or industrial facilities, residential buildings, 
 
 
10400SB0025ham004- 1005 -LRB104 16098 AAS 29398 a

1and such other public or privately owned buildings as the 
2Director deems necessary for relocation. The Agency is 
3authorized to operate a relocation program, and to pay such 
4costs of relocation as are provided in the federal "Uniform 
5Relocation Assistance and Real Property Acquisition Policies 
6Act", Public Law 91-646. The Director is authorized to exceed 
7the maximum payments provided pursuant to the federal "Uniform 
8Relocation Assistance and Real Property Acquisition Policies 
9Act" if necessary to assure the provision of decent, safe, and 
10sanitary housing, or to secure a suitable alternate location. 
11Payments issued under this Section shall be made from the 
12Low-level Radioactive Waste Facility Development and Operation 
13Fund established by the Illinois Low-Level Radioactive Waste 
14Management Act.
15(Source: P.A. 103-569, eff. 6-1-24.)
 
16    Section 90-80. The Radioactive Waste Tracking and 
17Permitting Act is amended by changing Sections 10 and 15 as 
18follows:
 
19    (420 ILCS 37/10)
20    Sec. 10. Definitions. As used in this Act:    
21    (a) "Agency" or "IEMA-OHS" means the Illinois Emergency 
22Management Agency and Office of Homeland Security, or its 
23successor agency.
24    (b) "Director" means the Director of the Agency.
 
 
10400SB0025ham004- 1006 -LRB104 16098 AAS 29398 a

1    (c) "Disposal" means the isolation of waste from the 
2biosphere in a permanent facility designed for that purpose.
3    (d) "Facility" means a parcel of land or a site, together 
4with structures, equipment, and improvements on or appurtenant 
5to the land or site, that is used or is being developed for the 
6treatment, storage, or disposal of low-level radioactive 
7waste.
8    (e) "Low-level radioactive waste" or "waste" means 
9radioactive waste not classified as (1) high-level radioactive 
10waste, (2) transuranic waste, (3) spent nuclear fuel, or (4) 
11byproduct material as defined in Sections 11e(2), 11e(3), and 
1211e(4) of the Atomic Energy Act (42 U.S.C. 2014). This 
13definition shall apply notwithstanding any declaration by the 
14federal government, a state, or any regulatory agency that any 
15radioactive material is exempt from any regulatory control.
16    (e-5) "Nuclear facilities" means nuclear power plants, 
17facilities housing nuclear test and research reactors, 
18facilities for the chemical conversion of uranium, and 
19facilities for the storage of spent nuclear fuel or high-level 
20radioactive waste.
21    (e-10) "Nuclear power plant" or "nuclear steam-generating 
22facility" means a thermal power plant in which the energy 
23(heat) released by the fissioning of nuclear fuel is used to 
24boil water to produce steam.
25    (e-15) "Nuclear power reactor" means an apparatus, other 
26than an atomic weapon, designed or used to sustain nuclear 
 
 
10400SB0025ham004- 1007 -LRB104 16098 AAS 29398 a

1fission in a self-supporting chain reaction.
2    (e-20) (Blank). "Small modular reactor" or "SMR" means an 
3advanced nuclear reactor: (1) with a rated nameplate capacity 
4of 300 electrical megawatts or less; and (2) that may be 
5constructed and operated in combination with similar reactors 
6at a single site.
7    (f) "Person" means an individual, corporation, business 
8enterprise, or other legal entity, public or private, or any 
9legal successor, representative, agent, or agency of that 
10individual, corporation, business enterprise, or legal entity.
11    (g) "Regional facility" or "disposal facility" means a 
12facility that is located in Illinois and established by 
13Illinois, under designation of Illinois as a host state by the 
14Commission for disposal of waste.
15    (h) "Storage" means the temporary holding of waste for 
16treatment or disposal for a period determined by Agency 
17regulations.
18    (i) "Treatment" means any method, technique, or process, 
19including storage for radioactive decay, that is designed to 
20change the physical, chemical, or biological characteristics 
21or composition of any waste in order to render the waste safer 
22for transport, storage, or disposal, amenable to recovery, 
23convertible to another usable material, or reduced in volume.
24(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24; 
25revised 7-31-24.)
 
 
 
10400SB0025ham004- 1008 -LRB104 16098 AAS 29398 a

1    (420 ILCS 37/15)
2    Sec. 15. Permit requirements for the storage, treatment, 
3and disposal of waste at a disposal facility.
4    (a) Upon adoption of regulations under subsection (c) of 
5this Section, no person shall deposit any low-level 
6radioactive waste at a storage, treatment, or disposal 
7facility in Illinois licensed under Section 8 of the Illinois 
8Low-Level Radioactive Waste Management Act without a permit 
9granted by the Agency.
10    (b) Upon adoption of regulations under subsection (c) of 
11this Section, no person shall operate a storage, treatment, or 
12disposal facility licensed under Section 8 of the Illinois 
13Low-Level Radioactive Waste Management Act without a permit 
14granted by the Agency.
15    (c) The Agency shall adopt regulations providing for the 
16issuance, suspension, and revocation of permits required under 
17subsections (a) and (b) of this Section. The regulations may 
18provide a system for tracking low-level radioactive waste to 
19ensure that waste that other states are responsible for 
20disposing of under federal law does not become the 
21responsibility of the State of Illinois. The regulations shall 
22be consistent with the Federal Hazardous Materials 
23Transportation Act.
24    (d) The Agency may enter into a contract or contracts for 
25operation of the system for tracking low-level radioactive 
26waste as provided in subsection (c) of this Section.
 
 
10400SB0025ham004- 1009 -LRB104 16098 AAS 29398 a

1    (e) A person who violates this Section or any regulation 
2promulgated under this Section shall be subject to a civil 
3penalty, not to exceed $10,000, for each violation. Each day a 
4violation continues shall constitute a separate offense. A 
5person who fails to pay a civil penalty imposed by a regulation 
6adopted under this Section, or any portion of the penalty, is 
7liable in a civil action in an amount not to exceed 4 times the 
8amount imposed and not paid. At the request of the Agency, the 
9Attorney General shall, on behalf of the State, bring an 
10action for the recovery of any civil penalty provided for by 
11this Section. Any civil penalties so recovered shall be 
12deposited into the Low-Level Radioactive Waste Facility 
13Operation Fund Low-Level Radioactive Waste Facility 
14Development and Operation.
15(Source: P.A. 103-569, eff. 6-1-24; 104-2, eff. 6-16-25.)
 
16    Section 90-85. The Radiation Protection Act of 1990 is 
17amended by changing Section 4 as follows:
 
18    (420 ILCS 40/4)  (from Ch. 111 1/2, par. 210-4)
19    (Section scheduled to be repealed on January 1, 2027) 
20    Sec. 4. Definitions.  As used in this Act: 
21    (a) "Accreditation" means the process by which the Agency 
22grants permission to persons meeting the requirements of this 
23Act and the Agency's rules and regulations to engage in the 
24practice of administering radiation to human beings. 
 
 
10400SB0025ham004- 1010 -LRB104 16098 AAS 29398 a

1    (a-2) "Agency" or "IEMA-OHS" means the Illinois Emergency 
2Management Agency and Office of Homeland Security, or its 
3successor agency. 
4    (a-3) "Assistant Director" means the Assistant Director of 
5the Agency. 
6    (a-5) "By-product material" means: (1) any radioactive 
7material (except special nuclear material) yielded in or made 
8radioactive by exposure to radiation incident to the process 
9of producing or utilizing special nuclear material; (2) the 
10tailings or wastes produced by the extraction or concentration 
11of uranium or thorium from any ore processed primarily for its 
12source material content, including discrete surface wastes 
13resulting from underground solution extraction processes but 
14not including underground ore bodies depleted by such solution 
15extraction processes; (3) any discrete source of radium-226 
16that is produced, extracted, or converted after extraction, 
17before, on, or after August 8, 2005, for use for a commercial, 
18medical, or research activity; (4) any material that has been 
19made radioactive by use of a particle accelerator and is 
20produced, extracted, or converted after extraction before, on, 
21or after August 8, 2005, for use for a commercial, medical, or 
22research activity; and (5) any discrete source of naturally 
23occurring radioactive material, other than source material, 
24that is extracted or converted after extraction for use in 
25commercial, medical, or research activity before, on, or after 
26August 8, 2005, and which the U.S. Nuclear Regulatory 
 
 
10400SB0025ham004- 1011 -LRB104 16098 AAS 29398 a

1Commission, in consultation with the Administrator of the 
2Environmental Protection Agency, the Secretary of Energy, the 
3Secretary of Homeland Security, and the head of any other 
4appropriate Federal agency, determines would pose a threat to 
5the public health and safety or the common defense and 
6security similar to the threat posed by a discrete source or 
7radium-226. 
8    (b) (Blank). 
9    (c) (Blank). 
10    (d) "General license" means a license, pursuant to 
11regulations promulgated by the Agency, effective without the 
12filing of an application to transfer, acquire, own, possess or 
13use quantities of, or devices or equipment utilizing, 
14radioactive material, including but not limited to by-product, 
15source or special nuclear materials. 
16    (d-1) "Identical in substance" means the regulations 
17promulgated by the Agency would require the same actions with 
18respect to ionizing radiation, for the same group of affected 
19persons, as would federal laws, regulations, or orders if any 
20federal agency, including but not limited to the Nuclear 
21Regulatory Commission, Food and Drug Administration, or 
22Environmental Protection Agency, administered the subject 
23program in Illinois. 
24    (d-3) "Mammography" means radiography of the breast 
25primarily for the purpose of enabling a physician to determine 
26the presence, size, location and extent of cancerous or 
 
 
10400SB0025ham004- 1012 -LRB104 16098 AAS 29398 a

1potentially cancerous tissue in the breast. 
2    (d-5) "Nuclear facilities" means nuclear power plants, 
3facilities housing nuclear test and research reactors, 
4facilities for the chemical conversion of uranium, and 
5facilities for the storage of spent nuclear fuel or high-level 
6radioactive waste.
7    (d-5.5) "Nuclear power plant" or "nuclear steam-generating 
8facility" means a thermal power plant in which the energy 
9(heat) released by the fissioning of nuclear fuel is used to 
10boil water to produce steam.
11    (d-5.10) "Nuclear power reactor" means an apparatus, other 
12than an atomic weapon, designed or used to sustain nuclear 
13fission in a self-supporting chain reaction.
14    (d-7) "Operator" is an individual, group of individuals, 
15partnership, firm, corporation, association, or other entity 
16conducting the business or activities carried on within a 
17radiation installation. 
18    (e) "Person" means any individual, corporation, 
19partnership, firm, association, trust, estate, public or 
20private institution, group, agency, political subdivision of 
21this State, any other State or political subdivision or agency 
22thereof, and any legal successor, representative, agent, or 
23agency of the foregoing, other than the United States Nuclear 
24Regulatory Commission, or any successor thereto, and other 
25than federal government agencies licensed by the United States 
26Nuclear Regulatory Commission, or any successor thereto. 
 
 
10400SB0025ham004- 1013 -LRB104 16098 AAS 29398 a

1"Person" also includes a federal entity (and its contractors) 
2if the federal entity agrees to be regulated by the State or as 
3otherwise allowed under federal law. 
4    (f) "Radiation" or "ionizing radiation" means gamma rays 
5and x-rays, alpha and beta particles, high speed electrons, 
6neutrons, protons, and other nuclear particles or 
7electromagnetic radiations capable of producing ions directly 
8or indirectly in their passage through matter; but does not 
9include sound or radio waves or visible, infrared, or 
10ultraviolet light. 
11    (f-5) "Radiation emergency" means the uncontrolled release 
12of radioactive material from a radiation installation which 
13poses a potential threat to the public health, welfare, and 
14safety. 
15    (g) "Radiation installation" is any location or facility 
16where radiation machines are used or where radioactive 
17material is produced, transported, stored, disposed of, or 
18used for any purpose. 
19    (h) "Radiation machine" is any device that produces 
20radiation when in use. 
21    (i) "Radioactive material" means any solid, liquid, or 
22gaseous substance which emits radiation spontaneously. 
23    (j) "Radiation source" or "source of ionizing radiation" 
24means a radiation machine or radioactive material as defined 
25herein. 
26    (j-5) (Blank). "Small modular reactor" or "SMR" means an 
 
 
10400SB0025ham004- 1014 -LRB104 16098 AAS 29398 a

1advanced nuclear reactor: (1) with a rated nameplate capacity 
2of 300 electrical megawatts or less; and (2) that may be 
3constructed and operated in combination with similar reactors 
4at a single site.
5    (k) "Source material" means (1) uranium, thorium, or any 
6other material which the Agency declares by order to be source 
7material after the United States Nuclear Regulatory 
8Commission, or any successor thereto, has determined the 
9material to be such; or (2) ores containing one or more of the 
10foregoing materials, in such concentration as the Agency 
11declares by order to be source material after the United 
12States Nuclear Regulatory Commission, or any successor 
13thereto, has determined the material in such concentration to 
14be source material. 
15    (l) "Special nuclear material" means (1) plutonium, 
16uranium 233, uranium enriched in the isotope 233 or in the 
17isotope 235, and any other material which the Agency declares 
18by order to be special nuclear material after the United 
19States Nuclear Regulatory Commission, or any successor 
20thereto, has determined the material to be such, but does not 
21include source material; or (2) any material artificially 
22enriched by any of the foregoing, but does not include source 
23material. 
24    (m) "Specific license" means a license, issued after 
25application, to use, manufacture, produce, transfer, receive, 
26acquire, own, or possess quantities of, or devices or 
 
 
10400SB0025ham004- 1015 -LRB104 16098 AAS 29398 a

1equipment utilizing radioactive materials. 
2(Source: P.A. 103-569, eff. 6-1-24.)
 
3    Section 90-90. The Uranium and Thorium Mill Tailings 
4Control Act is amended by changing Section 10 as follows:
 
5    (420 ILCS 42/10)
6    Sec. 10. Definitions. As used in this Act:
7    "Agency" or "IEMA-OHS" means the Illinois Emergency 
8Management Agency and Office of Homeland Security, or its 
9successor agency. 
10    "By-product material" means the tailings or wastes 
11produced by the extraction or concentration of uranium or 
12thorium from any ore processed primarily for its source 
13material content, including discrete surface wastes resulting 
14from underground solution extraction processes but not 
15including underground ore bodies depleted by such solution 
16extraction processes.
17    "Director" means the Director of the Agency.
18    "Nuclear facilities" means nuclear power plants, 
19facilities housing nuclear test and research reactors, 
20facilities for the chemical conversion of uranium, and 
21facilities for the storage of spent nuclear fuel or high-level 
22radioactive waste.
23    "Nuclear power plant" or "nuclear steam-generating 
24facility" means a thermal power plant in which the energy 
 
 
10400SB0025ham004- 1016 -LRB104 16098 AAS 29398 a

1(heat) released by the fissioning of nuclear fuel is used to 
2boil water to produce steam.
3    "Nuclear power reactor" means an apparatus, other than an 
4atomic weapon, designed or used to sustain nuclear fission in 
5a self-supporting chain reaction.
6    "Person" means any individual, corporation, partnership, 
7firm, association, trust, estate, public or private 
8institution, group, agency, political subdivision of this 
9State, any other State or political subdivision or agency 
10thereof, and any legal successor, representative, agent, or 
11agency of the foregoing, other than the United States Nuclear 
12Regulatory Commission, or any successor thereto, and other 
13than federal government agencies licensed by the United States 
14Nuclear Regulatory Commission, or any successor thereto.
15    "Radiation emergency" means the uncontrolled release of 
16radioactive material from a radiation installation that poses 
17a potential threat to the public health, welfare, and safety.
18    "Small modular reactor" or "SMR" means an advanced nuclear 
19reactor: (1) with a rated nameplate capacity of 300 electrical 
20megawatts or less; and (2) that may be constructed and 
21operated in combination with similar reactors at a single 
22site.
23    "Source material" means (i) uranium, thorium, or any other 
24material that the Agency declares by order to be source 
25material after the United States Nuclear Regulatory Commission 
26or its successor has determined the material to be source 
 
 
10400SB0025ham004- 1017 -LRB104 16098 AAS 29398 a

1material; or (ii) ores containing one or more of those 
2materials in such concentration as the Agency declares by 
3order to be source material after the United States Nuclear 
4Regulatory Commission or its successor has determined the 
5material in such concentration to be source material.
6    "Specific license" means a license, issued after 
7application, to use, manufacture, produce, transfer, receive, 
8acquire, own, or possess quantities of radioactive materials 
9or devices or equipment utilizing radioactive materials.
10(Source: P.A. 103-569, eff. 6-1-24.)
 
11    Section 90-95. The Laser System Act of 1997 is amended by 
12changing Section 15 as follows:
 
13    (420 ILCS 56/15)
14    Sec. 15. Definitions. For the purposes of this Act, unless 
15the context requires otherwise:
16    "Agency" or "IEMA-OHS" means the Illinois Emergency 
17Management Agency and Office of Homeland Security, or its 
18successor agency.
19    "Director" means the Director of the Agency.
20    "FDA" means the Food and Drug Administration of the United 
21States Department of Health and Human Services.
22    "Laser installation" means a location or facility where 
23laser systems are produced, stored, disposed of, or used for 
24any purpose. "Laser installation" does not include any private 
 
 
10400SB0025ham004- 1018 -LRB104 16098 AAS 29398 a

1residence. 
2    "Laser installation operator" means an individual, group 
3of individuals, partnership, firm, corporation, association, 
4or other entity conducting any business or activity within a 
5laser installation. 
6    "Laser machine" means a device that is capable of 
7producing or projecting laser radiation when associated 
8controlled devices are operated.
9    "Laser radiation" means an electromagnetic radiation 
10emitted from a laser system and includes all reflected 
11radiation, any secondary radiation, or other forms of energy 
12resulting from the primary laser beam.
13    "Laser safety officer" means an individual who is 
14qualified by training and experience in the evaluation and 
15control of laser hazards, as evidenced by satisfaction of the 
16training and experience requirements adopted by the Agency 
17under subsection (b) of Section 16, and who is designated, 
18where required by Sections 16 and 17, by a laser installation 
19operator or temporary laser display operator to have the 
20authority and responsibility to establish and administer a 
21laser radiation protection program for a particular laser 
22installation or temporary laser display. 
23    "Laser system" means a device, laser projector, laser 
24machine, equipment, or other apparatus that applies a source 
25of energy to a gas, liquid, crystal, or other solid substances 
26or combination thereof in a manner that electromagnetic 
 
 
10400SB0025ham004- 1019 -LRB104 16098 AAS 29398 a

1radiations of a relatively uniform wave length are amplified 
2and emitted in a cohesive beam capable of transmitting the 
3energy developed in a manner that may be harmful to living 
4tissues, including, but not limited to, electromagnetic waves 
5in the range of visible, infrared, or ultraviolet light. Such 
6systems in schools, colleges, occupational schools, and State 
7colleges and other State institutions are also included in the 
8definition of "laser systems". "Laser system" includes laser 
9machines but does not include any device, machine, equipment, 
10or other apparatus used in the provision of communications 
11through fiber optic cable. 
12    "Nuclear facilities" means nuclear power plants, 
13facilities housing nuclear test and research reactors, 
14facilities for the chemical conversion of uranium, and 
15facilities for the storage of spent nuclear fuel or high-level 
16radioactive waste.
17    "Nuclear power plant" or "nuclear steam-generating 
18facility" means a thermal power plant in which the energy 
19(heat) released by the fissioning of nuclear fuel is used to 
20boil water to produce steam.
21    "Nuclear power reactor" means an apparatus, other than an 
22atomic weapon, designed or used to sustain nuclear fission in 
23a self-supporting chain reaction.
24    "Small modular reactor" or "SMR" means an advanced nuclear 
25reactor: (1) with a rated nameplate capacity of 300 electrical 
26megawatts or less; and (2) that may be constructed and 
 
 
10400SB0025ham004- 1020 -LRB104 16098 AAS 29398 a

1operated in combination with similar reactors at a single 
2site.
3    "Temporary laser display" means a visual effect display 
4created for a limited period of time at a laser installation by 
5a laser system that is not a permanent fixture in the laser 
6installation for the entertainment of the public or invitees, 
7regardless of whether admission is charged or whether the 
8laser display takes place indoors or outdoors. 
9    "Temporary laser display operator" means an individual, 
10group of individuals, partnership, firm, corporation, 
11association, or other entity conducting a temporary laser 
12display at a laser installation.
13(Source: P.A. 102-558, eff. 8-20-21; 103-277, eff. 7-28-23; 
14103-569, eff. 6-1-24.)
 
15
ARTICLE 99.

 
16    Section 99-97. Severability. The provisions of this Act 
17are severable under Section 1.31 of the Statute on Statutes.".