Rep. Jay Hoffman
Filed: 9/19/2025
 
 

 
 

 
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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 
 
 
10400SB0025ham002- 23 -LRB104 07069 AAS 28576 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 
 
 
10400SB0025ham002- 24 -LRB104 07069 AAS 28576 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 
 
 
10400SB0025ham002- 25 -LRB104 07069 AAS 28576 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 
 
 
10400SB0025ham002- 26 -LRB104 07069 AAS 28576 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 
 
 
10400SB0025ham002- 27 -LRB104 07069 AAS 28576 a

1    formal peer review of physicians or other health care 
2    professionals, or for the discussion of matters protected 
3    under the federal Patient Safety and Quality Improvement 
4    Act of 2005, and the regulations promulgated thereunder, 
5    including 42 C.F.R. Part 3 (73 FR 70732), or the federal 
6    Health Insurance Portability and Accountability Act of 
7    1996, and the regulations promulgated thereunder, 
8    including 45 C.F.R. Parts 160, 162, and 164, by a 
9    hospital, or other institution providing medical care, 
10    that is operated by the public body.
11        (18) Deliberations for decisions of the Prisoner 
12    Review Board.
13        (19) Review or discussion of applications received 
14    under the Experimental Organ Transplantation Procedures 
15    Act.
16        (20) The classification and discussion of matters 
17    classified as confidential or continued confidential by 
18    the State Government Suggestion Award Board.
19        (21) Discussion of minutes of meetings lawfully closed 
20    under this Act, whether for purposes of approval by the 
21    body of the minutes or semi-annual review of the minutes 
22    as mandated by Section 2.06.
23        (22) Deliberations for decisions of the State 
24    Emergency Medical Services Disciplinary Review Board.
25        (23) The operation by a municipality of a municipal 
26    utility or the operation of a municipal power agency or 
 
 
10400SB0025ham002- 28 -LRB104 07069 AAS 28576 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 
 
 
10400SB0025ham002- 32 -LRB104 07069 AAS 28576 a

1charged by law or ordinance with the responsibility to conduct 
2hearings, receive evidence or testimony and make 
3determinations based thereon, but does not include local 
4electoral boards when such bodies are considering petition 
5challenges.
6    (e) Final action. No final action may be taken at a closed 
7meeting. Final action shall be preceded by a public recital of 
8the nature of the matter being considered and other 
9information that will inform the public of the business being 
10conducted. 
11(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21; 
12102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff. 
137-28-23; 103-626, eff. 1-1-25.)
 
14    Section 1-95. The Public Utilities Act is amended by 
15changing Section 8-406 as follows:
 
16    (220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
17    Sec. 8-406. Certificate of public convenience and 
18necessity. 
19    (a) No public utility not owning any city or village 
20franchise nor engaged in performing any public service or in 
21furnishing any product or commodity within this State as of 
22July 1, 1921 and not possessing a certificate of public 
23convenience and necessity from the Illinois Commerce 
24Commission, the State Public Utilities Commission, or the 
 
 
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1Public Utilities Commission, at the time Public Act 84-617 
2goes into effect (January 1, 1986), shall transact any 
3business in this State until it shall have obtained a 
4certificate from the Commission that public convenience and 
5necessity require the transaction of such business. A 
6certificate of public convenience and necessity requiring the 
7transaction of public utility business in any area of this 
8State shall include authorization to the public utility 
9receiving the certificate of public convenience and necessity 
10to construct such plant, equipment, property, or facility as 
11is provided for under the terms and conditions of its tariff 
12and as is necessary to provide utility service and carry out 
13the transaction of public utility business by the public 
14utility in the designated area.
15    (b) No public utility shall begin the construction of any 
16new plant, equipment, property, or facility which is not in 
17substitution of any existing plant, equipment, property, or 
18facility, or any extension or alteration thereof or in 
19addition thereto, unless and until it shall have obtained from 
20the Commission a certificate that public convenience and 
21necessity require such construction. Whenever after a hearing 
22the Commission determines that any new construction or the 
23transaction of any business by a public utility will promote 
24the public convenience and is necessary thereto, it shall have 
25the power to issue certificates of public convenience and 
26necessity. The Commission shall determine that proposed 
 
 
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1construction will promote the public convenience and necessity 
2only if the utility demonstrates: (1) that the proposed 
3construction is necessary to provide adequate, reliable, and 
4efficient service to its customers and is the least-cost means 
5of satisfying the service needs of its customers or that the 
6proposed construction will promote the development of an 
7effectively competitive electricity market that operates 
8efficiently, is equitable to all customers, and is the least 
9cost means of satisfying those objectives; (2) that the 
10utility is capable of efficiently managing and supervising the 
11construction process and has taken sufficient action to ensure 
12adequate and efficient construction and supervision thereof; 
13and (3) that the utility is capable of financing the proposed 
14construction without significant adverse financial 
15consequences for the utility or its customers.
16    (b-5) As used in this subsection (b-5):
17    "Qualifying direct current applicant" means an entity that 
18seeks to provide direct current bulk transmission service for 
19the purpose of transporting electric energy in interstate 
20commerce.
21    "Qualifying direct current project" means a high voltage 
22direct current electric service line that crosses at least one 
23Illinois border, the Illinois portion of which is physically 
24located within the region of the Midcontinent Independent 
25System Operator, Inc., or its successor organization, and runs 
26through the counties of Pike, Scott, Greene, Macoupin, 
 
 
10400SB0025ham002- 35 -LRB104 07069 AAS 28576 a

1Montgomery, Christian, Shelby, Cumberland, and Clark, is 
2capable of transmitting electricity at voltages of 345 
3kilovolts or above, and may also include associated 
4interconnected alternating current interconnection facilities 
5in this State that are part of the proposed project and 
6reasonably necessary to connect the project with other 
7portions of the grid.
8    Notwithstanding any other provision of this Act, a 
9qualifying direct current applicant that does not own, 
10control, operate, or manage, within this State, any plant, 
11equipment, or property used or to be used for the transmission 
12of electricity at the time of its application or of the 
13Commission's order may file an application on or before 
14December 31, 2023 with the Commission pursuant to this Section 
15or Section 8-406.1 for, and the Commission may grant, a 
16certificate of public convenience and necessity to construct, 
17operate, and maintain a qualifying direct current project. The 
18qualifying direct current applicant may also include in the 
19application requests for authority under Section 8-503. The 
20Commission shall grant the application for a certificate of 
21public convenience and necessity and requests for authority 
22under Section 8-503 if it finds that the qualifying direct 
23current applicant and the proposed qualifying direct current 
24project satisfy the requirements of this subsection and 
25otherwise satisfy the criteria of this Section or Section 
268-406.1 and the criteria of Section 8-503, as applicable to 
 
 
10400SB0025ham002- 36 -LRB104 07069 AAS 28576 a

1the application and to the extent such criteria are not 
2superseded by the provisions of this subsection. The 
3Commission's order on the application for the certificate of 
4public convenience and necessity shall also include the 
5Commission's findings and determinations on the request or 
6requests for authority pursuant to Section 8-503. Prior to 
7filing its application under either this Section or Section 
88-406.1, the qualifying direct current applicant shall conduct 
93 public meetings in accordance with subsection (h) of this 
10Section. If the qualifying direct current applicant 
11demonstrates in its application that the proposed qualifying 
12direct current project is designed to deliver electricity to a 
13point or points on the electric transmission grid in either or 
14both the PJM Interconnection, LLC or the Midcontinent 
15Independent System Operator, Inc., or their respective 
16successor organizations, the proposed qualifying direct 
17current project shall be deemed to be, and the Commission 
18shall find it to be, for public use. If the qualifying direct 
19current applicant further demonstrates in its application that 
20the proposed transmission project has a capacity of 1,000 
21megawatts or larger and a voltage level of 345 kilovolts or 
22greater, the proposed transmission project shall be deemed to 
23satisfy, and the Commission shall find that it satisfies, the 
24criteria stated in item (1) of subsection (b) of this Section 
25or in paragraph (1) of subsection (f) of Section 8-406.1, as 
26applicable to the application, without the taking of 
 
 
10400SB0025ham002- 37 -LRB104 07069 AAS 28576 a

1additional evidence on these criteria. Prior to the transfer 
2of functional control of any transmission assets to a regional 
3transmission organization, a qualifying direct current 
4applicant shall request Commission approval to join a regional 
5transmission organization in an application filed pursuant to 
6this subsection (b-5) or separately pursuant to Section 7-102 
7of this Act. The Commission may grant permission to a 
8qualifying direct current applicant to join a regional 
9transmission organization if it finds that the membership, and 
10associated transfer of functional control of transmission 
11assets, benefits Illinois customers in light of the attendant 
12costs and is otherwise in the public interest. Nothing in this 
13subsection (b-5) requires a qualifying direct current 
14applicant to join a regional transmission organization. 
15Nothing in this subsection (b-5) requires the owner or 
16operator of a high voltage direct current transmission line 
17that is not a qualifying direct current project to obtain a 
18certificate of public convenience and necessity to the extent 
19it is not otherwise required by this Section 8-406 or any other 
20provision of this Act. 
21    (c) As used in this subsection (c):
22    "Decommissioning" has the meaning given to that term in 
23subsection (a) of Section 8-508.1.
24    "Nuclear power reactor" has the meaning given to that term 
25in Section 8 of the Nuclear Safety Law of 2004. 
26    After the effective date of this amendatory Act of the 
 
 
10400SB0025ham002- 38 -LRB104 07069 AAS 28576 a

1103rd General Assembly, no construction shall commence on any 
2new nuclear power reactor with a nameplate capacity of more 
3than 300 megawatts of electricity to be located within this 
4State, and no certificate of public convenience and necessity 
5or other authorization shall be issued therefor by the 
6Commission, until the Illinois Emergency Management Agency and 
7Office of Homeland Security, in consultation with the Illinois 
8Environmental Protection Agency and the Illinois Department of 
9Natural Resources, finds that the United States Government, 
10through its authorized agency, has identified and approved a 
11demonstrable technology or means for the disposal of high 
12level nuclear waste, or until such construction has been 
13specifically approved by a statute enacted by the General 
14Assembly. Beginning January 1, 2026, construction may commence 
15on a new nuclear power reactor with a nameplate capacity of 300 
16megawatts of electricity or less within this State if the 
17entity constructing the new nuclear power reactor has obtained 
18all permits, licenses, permissions, or approvals governing the 
19construction, operation, and funding of decommissioning of 
20such nuclear power reactors required by: (1) this Act; (2) any 
21rules adopted by the Illinois Emergency Management Agency and 
22Office of Homeland Security under the authority of this Act; 
23(3) any applicable federal statutes, including, but not 
24limited to, the Atomic Energy Act of 1954, the Energy 
25Reorganization Act of 1974, the Low-Level Radioactive Waste 
26Policy Amendments Act of 1985, and the Energy Policy Act of 
 
 
10400SB0025ham002- 39 -LRB104 07069 AAS 28576 a

11992; (4) any regulations promulgated or enforced by the U.S. 
2Nuclear Regulatory Commission, including, but not limited to, 
3those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of 
4the Code of Federal Regulations, as from time to time amended; 
5and (5) any other federal or State statute, rule, or 
6regulation governing the permitting, licensing, operation, or 
7decommissioning of such nuclear power reactors. None of the 
8rules developed by the Illinois Emergency Management Agency 
9and Office of Homeland Security or any other State agency, 
10board, or commission pursuant to this Act shall be construed 
11to supersede the authority of the U.S. Nuclear Regulatory 
12Commission. The changes made by this amendatory Act of the 
13103rd General Assembly shall not apply to the uprate, renewal, 
14or subsequent renewal of any license for an existing nuclear 
15power reactor that began operation prior to the effective date 
16of this amendatory Act of the 103rd General Assembly. 
17    None of the changes made in this amendatory Act of the 
18103rd General Assembly are intended to authorize the 
19construction of nuclear power plants powered by nuclear power 
20reactors that are not either: (1) small modular nuclear 
21reactors; or (2) nuclear power reactors licensed by the U.S. 
22Nuclear Regulatory Commission to operate in this State prior 
23to the effective date of this amendatory Act of the 103rd 
24General Assembly. 
25    (d) In making its determination under subsection (b) of 
26this Section, the Commission shall attach primary weight to 
 
 
10400SB0025ham002- 40 -LRB104 07069 AAS 28576 a

1the cost or cost savings to the customers of the utility. The 
2Commission may consider any or all factors which will or may 
3affect such cost or cost savings, including the public 
4utility's engineering judgment regarding the materials used 
5for construction.
6    (e) The Commission may issue a temporary certificate which 
7shall remain in force not to exceed one year in cases of 
8emergency, to assure maintenance of adequate service or to 
9serve particular customers, without notice or hearing, pending 
10the determination of an application for a certificate, and may 
11by regulation exempt from the requirements of this Section 
12temporary acts or operations for which the issuance of a 
13certificate will not be required in the public interest.
14    A public utility shall not be required to obtain but may 
15apply for and obtain a certificate of public convenience and 
16necessity pursuant to this Section with respect to any matter 
17as to which it has received the authorization or order of the 
18Commission under the Electric Supplier Act, and any such 
19authorization or order granted a public utility by the 
20Commission under that Act shall as between public utilities be 
21deemed to be, and shall have except as provided in that Act the 
22same force and effect as, a certificate of public convenience 
23and necessity issued pursuant to this Section.
24    No electric cooperative shall be made or shall become a 
25party to or shall be entitled to be heard or to otherwise 
26appear or participate in any proceeding initiated under this 
 
 
10400SB0025ham002- 41 -LRB104 07069 AAS 28576 a

1Section for authorization of power plant construction and as 
2to matters as to which a remedy is available under the Electric 
3Supplier Act.
4    (f) Such certificates may be altered or modified by the 
5Commission, upon its own motion or upon application by the 
6person or corporation affected. Unless exercised within a 
7period of 2 years from the grant thereof, authority conferred 
8by a certificate of convenience and necessity issued by the 
9Commission shall be null and void.
10    No certificate of public convenience and necessity shall 
11be construed as granting a monopoly or an exclusive privilege, 
12immunity or franchise.
13    (g) A public utility that undertakes any of the actions 
14described in items (1) through (3) of this subsection (g) or 
15that has obtained approval pursuant to Section 8-406.1 of this 
16Act shall not be required to comply with the requirements of 
17this Section to the extent such requirements otherwise would 
18apply. For purposes of this Section and Section 8-406.1 of 
19this Act, "high voltage electric service line" means an 
20electric line having a design voltage of 69,000 100,000 or 
21more. For purposes of this subsection (g), a public utility 
22may do any of the following:
23        (1) replace or upgrade any existing high voltage 
24    electric service line and related facilities, 
25    notwithstanding its length or, subject to applicable 
26    Article VII requirements, ownership;
 
 
10400SB0025ham002- 42 -LRB104 07069 AAS 28576 a

1        (2) relocate any existing high voltage electric 
2    service line and related facilities, notwithstanding its 
3    length, to accommodate construction or expansion of a 
4    roadway or other transportation infrastructure; or
5        (3) construct a high voltage electric service line and 
6    related facilities that is constructed solely to serve a 
7    single customer's premises or to provide a generator 
8    interconnection to the public utility's transmission 
9    system and that will (i) pass under or over the premises 
10    owned by the customer or generator to be served; (ii) pass    
11    or under or over premises for which the customer or 
12    generator has secured the necessary right of way    
13    right-of-way; or (iii) be multi-circuited with the 
14    facilities of the public utility. 
15    (h) A public utility seeking to construct a high-voltage 
16electric service line and related facilities (Project) must 
17show that the utility has held a minimum of 2 pre-filing public 
18meetings to receive public comment concerning the Project in 
19each county where the Project is to be located, no earlier than 
206 months prior to filing an application for a certificate of 
21public convenience and necessity from the Commission. Notice 
22of the public meeting shall be published in a newspaper of 
23general circulation within the affected county once a week for 
243 consecutive weeks, beginning no earlier than one month prior 
25to the first public meeting. If the Project traverses 2 
26contiguous counties and where in one county the transmission 
 
 
10400SB0025ham002- 43 -LRB104 07069 AAS 28576 a

1line mileage and number of landowners over whose property the 
2proposed route traverses is one-fifth or less of the 
3transmission line mileage and number of such landowners of the 
4other county, then the utility may combine the 2 pre-filing 
5meetings in the county with the greater transmission line 
6mileage and affected landowners. All other requirements 
7regarding pre-filing meetings shall apply in both counties. 
8Notice of the public meeting, including a description of the 
9Project, must be provided in writing to the clerk of each 
10county where the Project is to be located. A representative of 
11the Commission shall be invited to each pre-filing public 
12meeting.
13    (h-5) A public utility seeking to construct a high-voltage 
14electric service line and related facilities must also show 
15that the Project has complied with training and competence 
16requirements under subsection (b) of Section 15 of the 
17Electric Transmission Systems Construction Standards Act. 
18    (i) For applications filed after August 18, 2015 (the 
19effective date of Public Act 99-399), the Commission shall, by 
20certified mail, notify each owner of record of land, as 
21identified in the records of the relevant county tax assessor, 
22included in the right-of-way over which the utility seeks in 
23its application to construct a high-voltage electric line of 
24the time and place scheduled for the initial hearing on the 
25public utility's application. The utility shall reimburse the 
26Commission for the cost of the postage and supplies incurred 
 
 
10400SB0025ham002- 44 -LRB104 07069 AAS 28576 a

1for mailing the notice.
2    (j) In determining whether to issue a certificate of 
3public convenience for a new electric generation facility to a 
4municipal power agency that is required to obtain such a 
5certificate to exercise its power of eminent domain pursuant 
6to Section 11-119.1-10 of the Illinois Municipal Code, the 
7Commission shall give due consideration to whether a 
8generation unit of similar size and type is part of the 
9municipal power agency's preferred portfolio or least-cost 
10plan for achieving renewable energy goals in its most recent 
11integrated resource plan, as described in subsection (d) of 
12Section 1-15 of the Municipal and Cooperative Electric Utility 
13Transparent Planning Act.    
14(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 
15102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 
166-1-24; 103-1066, eff. 2-20-25.)
 
17    Section 1-100. The General Not For Profit Corporation Act 
18of 1986 is amended by adding Section 108.22 as follows:
 
19    (805 ILCS 105/108.22 new)
20    Sec. 108.22. Distribution electric cooperatives.
21    (a) A distribution electric cooperative, as that term is 
22used in the Electric Supplier Act, shall maintain a publicly 
23accessible website and shall post the following documents and 
24information on its website:
 
 
10400SB0025ham002- 45 -LRB104 07069 AAS 28576 a

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

 
23    Section 5-1. Short title. This Article may be cited as the 
24Utility Data Access Act. References in this Article to "this 
 
 
10400SB0025ham002- 46 -LRB104 07069 AAS 28576 a

1Act" mean this Article.
 
2    Section 5-5. Findings. 
3    (a) The General Assembly finds and declares that 
4optimizing energy use through whole-building utility data 
5access is in the public interest because it provides 
6consumers, building owners, utilities, and states with 
7significant economic benefits. 
8    (b) The General Assembly further finds the following:
9        (1) implementing building energy use data access 
10    legislation catalyzes the development of a strong market 
11    for building energy services which will positively impact 
12    the State's economy through significant job growth;
13        (2) improving the energy use efficiency of the 
14    existing building stock is a key strategy to help preserve 
15    the affordability of rental housing;
16        (3) energy use reductions stemming from data access 
17    can result in direct cost savings to customers and in peak 
18    load reductions that benefit all ratepayers;
19        (4) data access programs allow utilities to maximize 
20    the value of their energy use efficiency portfolio by 
21    engaging customers and directing them to energy efficiency 
22    programs and by enabling utilities to target 
23    low-performing buildings; 
24        (5) implementing building data access enables building 
25    owners in the State to qualify for certain federal and 
 
 
10400SB0025ham002- 47 -LRB104 07069 AAS 28576 a

1    other incentives to help them improve their assets;
2        (6) energy use data access is the foundation of a 
3    successful efficiency strategy and enables building owners 
4    to track energy use performance over time, set performance 
5    goals, and justify cost-effective energy use upgrades; and
6        (7) absent whole-building energy use data access 
7    legislation, building owners lack an efficient, defined 
8    process to obtain energy performance of their buildings in 
9    a manner that protects consumer confidentiality.
 
10    Section 5-10. Definitions. As used in this Act:
11    "Account holder" or "customer" means the person or entity 
12authorized to access or modify utility account details. 
13    "Aggregated usage data" means an aggregation of covered 
14usage data, where all data associated with a qualified 
15building or qualified property, including, but not limited to, 
16data from tenant meters and from owner meters, are combined 
17into one collective data point per utility data type, per time 
18period, and where any unique identifiers or other personal 
19information are removed or dissociated from individual meter 
20data.
21    "Aggregation threshold" means 3 or more unique 
22nonresidential qualified accounts or any combination of 5 or 
23more residential and nonresidential unique qualified accounts 
24of a property or building during the period for which data is 
25requested.
 
 
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1    "Benchmarking tool" means the ENERGY STAR Portfolio 
2Manager web-based tool or any prudent and cost-effective 
3alternative system or tool approved by the Commission should 
4ENERGY STAR Portfolio Manager become inoperative or no longer 
5useful to achieving the policy goals of the State of Illinois 
6that (i) enables the periodic entry of a building's energy use 
7data and other descriptive information about a building and 
8(ii) rates a building's energy efficiency against that of 
9comparable buildings nationwide.
10    "Commission" means the Illinois Commerce Commission.
11    "Covered usage data" means electric data collected from 
12one or more utility meters that reflects the quantity and 
13period of utility usage in the building, property, or portion 
14thereof.
15    "Data recipient" means:
16        (1) an owner of the property or building;
17        (2) an owner of a portion of a property with regard to 
18    covered usage data only for the utility consumption the 
19    owner or the owner's tenants, if any, pay for and consume 
20    in the owned portion;
21        (3) a tenant with regard to covered usage data only 
22    for the utility consumption the tenant or the tenant's 
23    subtenants, if any, pay for and consume in the space 
24    leased by the tenant;
25        (4) the board, in the case of a condominium or 
26    cooperative ownership of the property or building; or
 
 
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1        (5) an agent authorized to receive the covered usage 
2    data by anyone in paragraphs (1) through (4).
3    "Property" means:
4        (1) a single tax parcel;
5        (2) 2 or more tax parcels held in the cooperative or 
6    condominium form of ownership and governed by a single 
7    board of managers; or
8        (3) 2 or more colocated tax parcels owned or 
9    controlled by the same entity.
10    "Qualified account" means a utility account that serves 
11some or all of a building or property for which covered usage 
12data is requested and that, as affirmed by the data recipient, 
13was not controlled by the data recipient or its subsidiary 
14during the time period for which covered usage data is 
15requested.
16    "Qualified building" means a building that meets the 
17aggregation threshold.
18    "Qualified data recipient" means a data recipient with 
19respect to a qualified property or qualified building.
20    "Qualified property" means a property that meets the 
21aggregation threshold.
22    "Qualified utility" means an electric utility that serves 
23at least 500,000 customers in the State.
24    "Utility" means an entity that is an electric utility with 
25over 500,000 customers in this State and that is a public 
26utility, as defined in Section 3-105 of the Public Utilities 
 
 
10400SB0025ham002- 50 -LRB104 07069 AAS 28576 a

1Act.
2    "Utility data type" means electric.
 
3    Section 5-15. Utility data access. 
4    (a) Within 90 days after the effective date of this Act, 
5the Commission shall open a proceeding to establish by rule, 
6consistent with the Illinois Administrative Procedure Act and 
7the requirements of subsection (c), procedures to implement 
8the requirements of this Section. The Commission shall 
9consider industry best practices along with Illinois law, 
10rules, and Commission orders in developing the implementing 
11rules. The governing authority of a public utility district, 
12municipally owned utility, or cooperative utility may adopt a 
13rule adopted by the Commission.
14    (b) No later than 2 years after the effective date of this 
15Act, the Commission shall adopt procedures through the 
16rulemaking proceeding identified in subsection (a) whereby:
17        (1) a utility shall retain all consumption data for a 
18    period of not less than 2 years;
19        (2) a qualified utility shall retain usage data in the 
20    possession of the utility on the effective date of this 
21    Act or that is subsequently generated by the utility, for 
22    a period 5 years or however long the utility retains usage 
23    data in its active billing system, whichever is longer;
24        (3) a utility shall honor an account holder's 
25    authorized request to transmit the account holder's 
 
 
10400SB0025ham002- 51 -LRB104 07069 AAS 28576 a

1    covered usage data held by the utility to any entity 
2    designated by the account holder;
3        (4) a qualified data recipient with respect to a 
4    qualified building or qualified property may request that 
5    a qualified utility provide aggregated usage data for the 
6    qualified building or qualified property. Aggregated usage 
7    data shall include identifiers of all meters associated 
8    with the aggregate data and any other information needed 
9    for data quality assurance;
10        (5) a utility shall establish a tool or process to 
11    enable qualified data recipients to request data under 
12    this subsection. The tool or process shall meet 
13    specifications established by the Commission;
14        (6) the account holder request process and utility 
15    delivery of requested data shall be convenient, secure, 
16    and at the Commission's direction requests to the utility 
17    may be submitted exclusively through an online portal; and
18        (7) a utility shall provide updates or corrections to 
19    any previously provided usage information on the schedule 
20    established in paragraph (5) of subsection (d). Data 
21    recipients may request and receive timely revisions 
22    correcting any previously provided usage information. A 
23    utility shall also provide usage information on the 
24    schedule established in paragraph (5) of subsection (d).
25    (c) Any covered usage data that a utility provides to a 
26data recipient under this Section must meet the following 
 
 
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1requirements:
2        (1) The covered usage data must be available to be 
3    requested online except that a nonqualified utility may 
4    provide only paper request forms upon showing of good 
5    cause. A utility's validation of the requester's identity 
6    shall be consistent with, and no more onerous than, the 
7    utility's then-current practices.
8        (2) The covered usage data must be provided to the 
9    data recipient in a timeframe, frequency, and format and 
10    be delivered by a method as may be determined by the 
11    Commission.
12    (d) Any covered usage data that a qualified utility 
13provides to a data recipient under this Section must:
14        (1) be provided to the data recipient within 30 days 
15    after receiving the data recipient's valid request if the 
16    request is received after the effective date of the 
17    rulemaking identified in subsection (a) of this Section;
18        (2) for any initial upload of data to a data recipient 
19    and subject to subsection (j) of this Section, a data 
20    recipient must include all the data for the time period 
21    required in paragraph (2) of subsection (b), regardless of 
22    whether the data recipient had a business relationship 
23    with the building or property during that period;
24        (3) include all necessary data and available usage 
25    data points for data recipients to comply with reporting 
26    requirements to which they are subject, including any such 
 
 
10400SB0025ham002- 53 -LRB104 07069 AAS 28576 a

1    usage data that the utility possesses;
2        (4) be directly uploaded to the benchmarking tool 
3    account, or delivered in another format approved by the 
4    Commission, depending on utility size under subsection 
5    (e);
6        (5) be provided to the data recipient according to a 
7    schedule set by the Commission, but no less than monthly;
8        (6) be provided until the data recipient revokes the 
9    request for usage data or is no longer a data recipient or 
10    is no longer a qualified data recipient with respect to 
11    aggregated usage data;
12        (7) be accompanied by a list of all meters associated 
13    with the covered usage data, including, but not limited 
14    to, aggregated usage data, and shall be accompanied by any 
15    other information the Commission deems necessary including 
16    for data quality assurance; and
17        (8) be provided at no cost to the data recipient. 
18    (e) The Commission shall direct that covered usage data 
19shall be delivered to the data recipient in a standard format 
20consistent with the benchmarking tool at the data recipient's 
21request. The Commission shall direct electric utilities that 
22serve at least 500,000 customers in the State to provide 
23requested data by direct upload to the benchmarking tool and 
24associate the data with the data recipient's benchmarking tool 
25account.
26    (f) To ensure the validity and usefulness of covered usage 
 
 
10400SB0025ham002- 54 -LRB104 07069 AAS 28576 a

1data, the utility shall provide the best available consumption 
2and other information, consistent with the utility's records 
3as presented to account holders on the utility's customer 
4portal and captured at the meter level.
5    (g) Once covered usage data has been made available to a 
6duly authorized data recipient, such data may not be deleted 
7or altered by a utility system, except as is necessary to 
8correct errors or reflect rebills or is affected as part of the 
9utility's billing data retention policy. If previously 
10provided covered usage data is changed to correct errors, 
11notification must be provided to the data recipient.
12    (h) Within 180 days after the effective date of this Act, 
13the Commission shall adopt a standard form for a utility 
14account holder to authorize the sharing of the utility account 
15holder's covered usage data.
16    (i) For properties that do not meet the aggregation 
17threshold and therefore require account holder authorization, 
18the utility shall provide covered usage data to data 
19recipients upon account holder authorization, which:
20        (1) may be provided in Commission-approved form;
21        (2) may be provided in a lease agreement provision; 
22    and
23        (3) remains valid until the account holder revokes it, 
24    regardless of how the authorization is provided. 
25    (j) Access to covered usage data under this Section shall 
26be subject to any rules the Commission has adopted or may 
 
 
10400SB0025ham002- 55 -LRB104 07069 AAS 28576 a

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

 
23    Section 90-5. The Department of Commerce and Economic 
24Opportunity Law of the Civil Administrative Code of Illinois 
 
 
10400SB0025ham002- 56 -LRB104 07069 AAS 28576 a

1is amended by changing Section 605-1075 as follows:
 
2    (20 ILCS 605/605-1075)
3    Sec. 605-1075. Energy Transition Assistance Fund.
4    (a) The General Assembly hereby declares that management 
5of several economic development programs requires a 
6consolidated funding source to improve resource efficiency. 
7The General Assembly specifically recognizes that properly 
8serving communities and workers impacted by the energy 
9transition requires that the Department of Commerce and 
10Economic Opportunity have access to the resources required for 
11the execution of the programs for workforce and contractor 
12development, just transition investments and community 
13support, and the implementation and administration of energy 
14and justice efforts by the State.
15    (b) The Department shall be responsible for the 
16administration of the Energy Transition Assistance Fund and 
17shall allocate funding on the basis of priorities established 
18in this Section. Each year, the Department shall determine the 
19available amount of resources in the Fund that can be 
20allocated to the programs identified in this Section, and 
21allocate the funding accordingly. The Department shall, to the 
22extent practical, consider both the short-term and long-term 
23costs of the programs and allocate funding so that the 
24Department is able to cover both the short-term and long-term 
25costs of these programs using projected revenue.
 
 
10400SB0025ham002- 57 -LRB104 07069 AAS 28576 a

1    The available funding for each year shall be allocated 
2from the Fund in the following order of priority:
3        (1) for costs related to the Clean Jobs Workforce 
4    Network Program, up to $21,000,000 annually prior to June 
5    1, 2023; and $24,333,333 annually from June 1, 2023 to May 
6    30, 2026; and $26,020,736 annually thereafter;
7        (2) for costs related to the Clean Energy Contractor 
8    Incubator Program, up to $21,000,000 annually prior to 
9    June 1, 2026 and up to $22,687,403 thereafter;
10        (3) for costs related to the Clean Energy Primes 
11    Contractor Accelerator Program, up to $9,000,000 annually;
12        (4) for costs related to the Barrier Reduction 
13    Program, up to $21,000,000 annually prior to June 1, 2026 
14    and up to $22,143,079 annually thereafter;
15        (5) for costs related to the Jobs and Environmental 
16    Justice Grant Program, up to $34,000,000 annually;
17        (6) for costs related to the Returning Residents Clean 
18    Jobs Training Program, up to $6,000,000 annually;
19        (7) for costs related to Energy Transition Navigators, 
20    up to $6,000,000 annually;
21        (8) for costs related to the Illinois Climate Works 
22    Preapprenticeship Program, up to $10,000,000 annually;
23        (9) for costs related to Energy Transition Community 
24    Support Grants, up to $40,000,000 annually;
25        (10) for costs related to the Displaced Energy Worker 
26    Dependent Scholarship, upon request by the Illinois 
 
 
10400SB0025ham002- 58 -LRB104 07069 AAS 28576 a

1    Student Assistance Commission, up to $1,100,000 annually;
2        (11) up to $10,000,000 annually shall be transferred 
3    to the Public Utilities Fund for use by the Illinois 
4    Commerce Commission for costs of administering the changes 
5    made to the Public Utilities Act by this amendatory Act of 
6    the 102nd General Assembly;
7        (12) up to $4,000,000 annually shall be transferred to 
8    the Illinois Power Agency Operations Fund for use by the 
9    Illinois Power Agency; and
10        (13) for costs related to the Clean Energy Jobs and 
11    Justice Fund, up to $1,000,000 annually.
12    The Department is authorized to utilize up to 10% of the 
13Energy Transition Assistance Fund for administrative and 
14operational expenses to implement the requirements of this 
15Act.
16    (b-5) Beginning January 1, 2028, the Department shall 
17transfer up to $84,800,000 annually to the Electric Vehicle 
18and Charging Fund for costs related to beneficial 
19electrification programs, as defined in Section 45 of the 
20Electric Vehicle Act. The Environmental Protection Agency may 
21utilize up to 3% of the annual allocation under this 
22subsection (b-5) for administrative and operational expenses.    
23    (c) Within 30 days after 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 
26report to the Department its total kilowatt-hours of energy 
 
 
10400SB0025ham002- 59 -LRB104 07069 AAS 28576 a

1delivered during the 12 months ending on the immediately 
2preceding May 31. By October 31, 2021 and each October 31 
3thereafter, each electric utility serving more than 500,000 
4customers in the State shall report to the Department its 
5total kilowatt-hours of energy delivered during the 12 months 
6ending on the immediately preceding May 31.
7    (d) The Department shall, within 60 days after the 
8effective date of this amendatory Act of the 102nd General 
9Assembly:
10        (1) determine the amount necessary, but not more than 
11    $180,000,000, to meet the funding needs of the programs 
12    reliant upon the Energy Transition Assistance Fund as a 
13    revenue source for the period between the effective date 
14    of this amendatory Act of the 102nd General Assembly and 
15    December 31, 2021;
16        (2) determine, based on the kilowatt-hour deliveries 
17    for the 12 months ending May 31, 2021 reported by the 
18    electric utilities under subsection (c), the total energy 
19    transition assistance charge to be allocated to each 
20    electric utility for the period between the effective date 
21    of this amendatory Act of the 102nd General Assembly and 
22    December 31, 2021; and
23        (3) report the total energy transition assistance 
24    charge applicable until December 31, 2021 to each electric 
25    utility serving more than 500,000 customers in the State 
26    and the Illinois Commerce Commission for purposes of 
 
 
10400SB0025ham002- 60 -LRB104 07069 AAS 28576 a

1    filing the tariff pursuant to Section 16-108.30 of the 
2    Public Utilities Act.
3    (e) The Department shall by November 30, 2021, and each 
4November 30 thereafter:
5        (1) determine the amount necessary, but not more than 
6    $180,000,000 plus the amount needed to fund the programs 
7    described in subsection (b-5), to meet the funding needs 
8    of the programs reliant upon the Energy Transition 
9    Assistance Fund as a revenue source for the immediately 
10    following calendar year;
11        (2) determine, based on the kilowatt-hour deliveries 
12    for the 12 months ending on the immediately preceding May 
13    31 reported to it by the electric utilities under 
14    subsection (c), the total energy transition assistance 
15    charge to be allocated to each electric utility for the 
16    immediately following calendar year; and
17        (3) report the energy transition assistance charge 
18    applicable for the immediately following calendar year to 
19    each electric utility serving more than 500,000 customers 
20    in the State and the Illinois Commerce Commission for 
21    purposes of filing the tariff pursuant to Section 
22    16-108.30 of the Public Utilities Act.
23    (f) The energy transition assistance charge may not exceed 
24$180,000,000 plus the amount needed to fund the programs 
25described in subsection (b-5) annually. If, at the end of the 
26calendar year, any surplus remains in the Energy Transition 
 
 
10400SB0025ham002- 61 -LRB104 07069 AAS 28576 a

1Assistance Fund, the Department may allocate the surplus from 
2the fund in the following order of priority:
3        (1) for costs related to the development of the 
4    Stretch Energy Codes and other standards at the Capital 
5    Development Board, up to $500,000 annually, at the request 
6    of the Board;
7        (2) up to $7,000,000 annually shall be transferred to 
8    the Energy Efficiency Trust Fund and Clean Air Act Permit 
9    Fund for use by the Environmental Protection Agency for 
10    costs related to energy efficiency and weatherization, and 
11    costs of implementation, administration, and enforcement 
12    of the Clean Air Act; and
13        (3) for costs related to State fleet electrification 
14    at the Department of Central Management Services, up to 
15    $10,000,000 annually, at the request of the Department.
16(Source: P.A. 102-662, eff. 9-15-21.)
 
17    Section 90-6. The Electric Vehicle Act is amended by 
18changing Section 45 as follows:
 
19    (20 ILCS 627/45)
20    Sec. 45. Beneficial electrification.
21    (a) It is the intent of the General Assembly to decrease 
22reliance on fossil fuels, reduce pollution from the 
23transportation sector, increase access to electrification for 
24all consumers, and ensure that electric vehicle adoption and 
 
 
10400SB0025ham002- 62 -LRB104 07069 AAS 28576 a

1increased electricity usage and demand do not place 
2significant additional burdens on the electric system and 
3create benefits for Illinois residents.
4        (1) Illinois should increase the adoption of electric 
5    vehicles in the State to 1,000,000 by 2030.
6        (2) Illinois should strive to be the best state in the 
7    nation in which to drive and manufacture electric 
8    vehicles.
9        (3) Widespread adoption of electric vehicles is 
10    necessary to electrify the transportation sector, 
11    diversify the transportation fuel mix, drive economic 
12    development, and protect air quality.
13        (4) Accelerating the adoption of electric vehicles 
14    will drive the decarbonization of Illinois' transportation 
15    sector.
16        (5) Expanded infrastructure investment will help 
17    Illinois more rapidly decarbonize the transportation 
18    sector.
19        (6) Statewide adoption of electric vehicles requires 
20    increasing access to electrification for all consumers.
21        (7) Widespread adoption of electric vehicles requires 
22    increasing public access to charging equipment throughout 
23    Illinois, especially in low-income and environmental 
24    justice communities, where levels of air pollution burden 
25    tend to be higher.
26        (8) Widespread adoption of electric vehicles and 
 
 
10400SB0025ham002- 63 -LRB104 07069 AAS 28576 a

1    charging equipment has the potential to provide customers 
2    with fuel cost savings and electric utility customers with 
3    cost-saving benefits.
4        (9) Widespread adoption of electric vehicles can 
5    improve an electric utility's electric system efficiency 
6    and operational flexibility, including the ability of the 
7    electric utility to integrate renewable energy resources 
8    and make use of off-peak generation resources that support 
9    the operation of charging equipment.
10        (10) Widespread adoption of electric vehicles should 
11    stimulate innovation, competition, and increased choices 
12    in charging equipment and networks and should also attract 
13    private capital investments and create high-quality jobs 
14    in Illinois.
15    (b) As used in this Section:
16    "Agency" means the Environmental Protection Agency.
17    "Beneficial electrification programs" means programs that 
18lower carbon dioxide emissions, replace fossil fuel use, 
19create cost savings, improve electric grid operations, reduce 
20increases to peak demand, improve electric usage load shape, 
21and align electric usage with times of renewable generation. 
22All beneficial electrification programs shall provide for 
23incentives such that customers are induced to use electricity 
24at times of low overall system usage or at times when 
25generation from renewable energy sources is high. "Beneficial 
26electrification programs" include a portfolio of the 
 
 
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1following:
2        (1) time-of-use electric rates;
3        (2) hourly pricing electric rates;
4        (3) optimized charging programs or programs that 
5    encourage charging at times beneficial to the electric 
6    grid;
7        (4) optional demand-response programs specifically 
8    related to electrification efforts;
9        (5) incentives for electrification and associated 
10    infrastructure tied to using electricity at off-peak 
11    times;
12        (6) incentives for electrification and associated 
13    infrastructure targeted to medium-duty and heavy-duty 
14    vehicles used by transit agencies;
15        (7) incentives for electrification and associated 
16    infrastructure targeted to school buses;
17        (8) incentives for electrification and associated 
18    infrastructure for medium-duty and heavy-duty government 
19    and private fleet vehicles;
20        (9) low-income programs that provide access to 
21    electric vehicles for communities where car ownership or 
22    new car ownership is not common;
23        (10) incentives for electrification in eligible 
24    communities;
25        (11) incentives or programs to enable quicker adoption 
26    of electric vehicles by developing public charging 
 
 
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1    stations in dense areas, workplaces, and low-income 
2    communities;
3        (12) incentives or programs to develop electric 
4    vehicle infrastructure that minimizes range anxiety, 
5    filling the gaps in deployment, particularly in rural 
6    areas and along highway corridors;
7        (13) incentives to encourage the development of 
8    electrification and renewable energy generation in close 
9    proximity in order to reduce grid congestion;
10        (14) offer support to low-income communities who are 
11    experiencing financial and accessibility barriers such 
12    that electric vehicle ownership is not an option; and
13        (15) other such programs as defined by the Commission.
14    "Black, indigenous, and people of color" or "BIPOC" means 
15people who are members of the groups described in 
16subparagraphs (a) through (e) of paragraph (A) of subsection 
17(1) of Section 2 of the Business Enterprise for Minorities, 
18Women, and Persons with Disabilities Act.
19    "Commission" means the Illinois Commerce Commission.
20    "Coordinator" means the Electric Vehicle Coordinator.
21    "Electric vehicle" means a vehicle that is exclusively 
22powered by and refueled by electricity, must be plugged in to 
23charge, and is licensed to drive on public roadways. "Electric 
24vehicle" does not include electric mopeds, electric 
25off-highway vehicles, or hybrid electric vehicles and 
26extended-range electric vehicles that are also equipped with 
 
 
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1conventional fueled propulsion or auxiliary engines.
2    "Electric vehicle charging station" means a station that 
3delivers electricity from a source outside an electric vehicle 
4into one or more electric vehicles.
5    "Environmental justice communities" means the definition 
6of that term based on existing methodologies and findings, 
7used and as may be updated by the Illinois Power Agency and its 
8program administrator in the Illinois Solar for All Program.
9    "Equity investment eligible community" or "eligible 
10community" means the geographic areas throughout Illinois 
11which would most benefit from equitable investments by the 
12State designed to combat discrimination and foster sustainable 
13economic growth. Specifically, "eligible community" means the 
14following areas:
15        (1) areas where residents have been historically 
16    excluded from economic opportunities, including 
17    opportunities in the energy sector, as defined pursuant to 
18    Section 10-40 of the Cannabis Regulation and Tax Act; and
19        (2) areas where residents have been historically 
20    subject to disproportionate burdens of pollution, 
21    including pollution from the energy sector, as established 
22    by environmental justice communities as defined by the 
23    Illinois Power Agency pursuant to Illinois Power Agency 
24    Act, excluding any racial or ethnic indicators.
25    "Equity investment eligible person" or "eligible person" 
26means the persons who would most benefit from equitable 
 
 
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1investments by the State designed to combat discrimination and 
2foster sustainable economic growth. Specifically, "eligible 
3person" means the following people:
4        (1) persons whose primary residence is in an equity 
5    investment eligible community;
6        (2) persons who are graduates of or currently enrolled 
7    in the foster care system; or
8        (3) persons who were formerly incarcerated.
9    "Low-income" means persons and families whose income does 
10not exceed 80% of the state median income for the current State 
11fiscal year as established by the U.S. Department of Health 
12and Human Services.
13    "Make-ready infrastructure" means the electrical and 
14construction work necessary between the distribution circuit 
15to the connection point of charging equipment.
16    "Optimized charging programs" mean programs whereby owners 
17of electric vehicles can set their vehicles to be charged 
18based on the electric system's current demand, retail or 
19wholesale market rates, incentives, the carbon or other 
20pollution intensity of the electric generation mix, the 
21provision of grid services, efficient use of the electric 
22grid, or the availability of clean energy generation. 
23Optimized charging programs may be operated by utilities as 
24well as third parties.
25    (c) The Commission shall initiate a workshop process no 
26later than November 30, 2021 for the purpose of soliciting 
 
 
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1input on the design of beneficial electrification programs 
2that the utility shall offer. The workshop shall be 
3coordinated by the Staff of the Commission, or a facilitator 
4retained by Staff, and shall be organized and facilitated in a 
5manner that encourages representation from diverse 
6stakeholders, including stakeholders representing 
7environmental justice and low-income communities, and ensures 
8equitable opportunities for participation, without requiring 
9formal intervention or representation by an attorney.
10    The stakeholder workshop process shall take into 
11consideration the benefits of electric vehicle adoption and 
12barriers to adoption, including:
13        (1) the benefit of lower bills for customers who do 
14    not charge electric vehicles;
15        (2) benefits to the distribution system from electric 
16    vehicle usage;
17        (3) the avoidance and reduction in capacity costs from 
18    optimized charging and off-peak charging;
19        (4) energy price and cost reductions;
20        (5) environmental benefits, including greenhouse gas 
21    emission and other pollution reductions;
22        (6) current barriers to mass-market adoption, 
23    including cost of ownership and availability of charging 
24    stations;
25        (7) current barriers to increasing access among 
26    populations that have limited access to electric vehicle 
 
 
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1    ownership, communities significantly impacted by 
2    transportation-related pollution, and market segments that 
3    create disproportionate pollution impacts;
4        (8) benefits of and incentives for medium-duty and 
5    heavy-duty fleet vehicle electrification;
6        (9) opportunities for eligible communities to benefit 
7    from electrification;
8        (10) geographic areas and market segments that should 
9    be prioritized for electrification infrastructure 
10    investment.
11    The workshops shall consider barriers, incentives, 
12enabling rate structures, and other opportunities for the bill 
13reduction and environmental benefits described in this 
14subsection.
15    The workshop process shall conclude no later than February 
1628, 2022. Following the workshop, the Staff of the Commission, 
17or the facilitator retained by the Staff, shall prepare and 
18submit a report, no later than March 31, 2022, to the 
19Commission that includes, but is not limited to, 
20recommendations for transportation electrification investment 
21or incentives in the following areas:
22        (i) publicly accessible Level 2 and fast-charging 
23    stations, with a focus on bringing access to 
24    transportation electrification in densely populated areas 
25    and workplaces within eligible communities;
26        (ii) medium-duty and heavy-duty charging 
 
 
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1    infrastructure used by government and private fleet 
2    vehicles that serve or travel through environmental 
3    justice or eligible communities;
4        (iii) medium-duty and heavy-duty charging 
5    infrastructure used in school bus operations, whether 
6    private or public, that primarily serve governmental or 
7    educational institutions, and also serve or travel through 
8    environmental justice or eligible communities;
9        (iv) public transit medium-duty and heavy-duty 
10    charging infrastructure, developed in consultation with 
11    public transportation agencies; and
12        (v) publicly accessible Level 2 and fast-charging 
13    stations targeted to fill gaps in deployment, particularly 
14    in rural areas and along State highway corridors.
15    The report must also identify the participants in the 
16process, program designs proposed during the process, 
17estimates of the costs and benefits of proposed programs, any 
18material issues that remained unresolved at the conclusions of 
19such process, and any recommendations for workshop process 
20improvements. The report shall be used by the Commission to 
21inform and evaluate the cost-effectiveness cost effectiveness    
22and achievement of goals within the submitted Beneficial 
23Electrification Plans.
24    (d) No later than July 1, 2022, electric utilities serving 
25greater than 500,000 customers in the State shall file a 
26Beneficial Electrification Plan with the Illinois Commerce 
 
 
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1Commission for programs that start no later than January 1, 
22023. The plan shall take into consideration recommendations 
3from the workshop report described in this Section. Within 45 
4days after the filing of the Beneficial Electrification Plan, 
5the Commission shall, with reasonable notice, open an 
6investigation to consider whether the plan meets the 
7objectives and contains the information required by this 
8Section. The Commission shall determine if the proposed plan 
9is cost-beneficial and in the public interest. When 
10considering if the plan is in the public interest and 
11determining appropriate levels of cost recovery for 
12investments and expenditures related to programs proposed by 
13an electric utility, the Commission shall consider whether the 
14investments and other expenditures are designed and reasonably 
15expected to:
16        (1) maximize total energy cost savings and rate 
17    reductions so that nonparticipants can benefit;
18        (2) address environmental justice interests by 
19    ensuring there are significant opportunities for residents 
20    and businesses in eligible communities to directly 
21    participate in and benefit from beneficial electrification 
22    programs;
23        (3) support at least a 40% investment of make-ready 
24    infrastructure incentives to facilitate the rapid 
25    deployment of charging equipment in or serving 
26    environmental justice, low-income, and eligible 
 
 
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1    communities; however, nothing in this subsection is 
2    intended to require a specific amount of spending in a 
3    particular geographic area;
4        (4) support at least a 5% investment target in 
5    electrifying medium-duty and heavy-duty school bus and 
6    diesel public transportation vehicles located in or 
7    serving environmental justice, low-income, and eligible 
8    communities in order to provide those communities and 
9    businesses with greater economic investment, 
10    transportation opportunities, and a cleaner environment so 
11    they can directly benefit from transportation 
12    electrification efforts; however, nothing in this 
13    subsection is intended to require a specific amount of 
14    spending in a particular geographic area;
15        (5) stimulate innovation, competition, private 
16    investment, and increased consumer choices in electric 
17    vehicle charging equipment and networks;
18        (6) contribute to the reduction of carbon emissions 
19    and meeting air quality standards, including improving air 
20    quality in eligible communities who disproportionately 
21    suffer from emissions from the medium-duty and heavy-duty 
22    transportation sector;
23        (7) support the efficient and cost-effective use of 
24    the electric grid in a manner that supports electric 
25    vehicle charging operations; and
26        (8) provide resources to support private investment in 
 
 
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1    charging equipment for uses in public and private charging 
2    applications, including residential, multi-family, fleet, 
3    transit, community, and corridor applications.
4    The plan shall be determined to be cost-beneficial if the 
5total cost of beneficial electrification expenditures is less 
6than the net present value of increased electricity costs 
7(defined as marginal avoided energy, avoided capacity, and 
8avoided transmission and distribution system costs) avoided by 
9programs under the plan, the net present value of reductions 
10in other customer energy costs, net revenue from all electric 
11charging in the service territory, and the societal value of 
12reduced carbon emissions and surface-level pollutants, 
13particularly in environmental justice communities. The 
14calculation of costs and benefits should be based on net 
15impacts, including the impact on customer rates.
16    The Commission shall approve, approve with modifications, 
17or reject the plan within 270 days from the date of filing. The 
18Commission may approve the plan if it finds that the plan will 
19achieve the goals described in this Section and contains the 
20information described in this Section. Proceedings under this 
21Section shall proceed according to the rules provided by 
22Article IX of the Public Utilities Act. Information contained 
23in the approved plan shall be considered part of the record in 
24any Commission proceeding under Section 16-107.6 of the Public 
25Utilities Act, provided that a final order has not been 
26entered prior to the initial filing date. The Beneficial 
 
 
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1Electrification Plan shall specifically address, at a minimum, 
2the following:
3        (i) make-ready investments to facilitate the rapid 
4    deployment of charging equipment throughout the State, 
5    facilitate the electrification of public transit and other 
6    vehicle fleets in the light-duty, medium-duty, and 
7    heavy-duty sectors, and align with Agency-issued rebates 
8    for charging equipment;
9        (ii) the development and implementation of beneficial 
10    electrification programs, including time-of-use rates and 
11    their benefit for electric vehicle users and for all 
12    customers, optimized charging programs to achieve savings 
13    identified, and new contracts and compensation for 
14    services in those programs, through signals that allow 
15    electric vehicle charging to respond to local system 
16    conditions, manage critical peak periods, serve as a 
17    demand response or peak resource, and maximize renewable 
18    energy use and integration into the grid;
19        (iii) optional commercial tariffs utilizing 
20    alternatives to traditional demand-based rate structures 
21    to facilitate charging for light-duty, heavy-duty, and 
22    fleet electric vehicles;
23        (iv) financial and other challenges to electric 
24    vehicle usage in low-income communities, and strategies 
25    for overcoming those challenges, particularly in 
26    communities where and for people for whom car ownership is 
 
 
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1    not an option;
2        (v) methods of minimizing ratepayer impacts and 
3    exempting or minimizing, to the extent possible, 
4    low-income ratepayers from the costs associated with 
5    facilitating the expansion of electric vehicle charging;
6        (vi) plans to increase access to Level 3 Public 
7    Electric Vehicle Charging Infrastructure to serve vehicles 
8    that need quicker charging times and vehicles of persons 
9    who have no other access to charging infrastructure, 
10    regardless of whether those projects participate in 
11    optimized charging programs;
12        (vii) whether to establish charging standards for type 
13    of plugs eligible for investment or incentive programs, 
14    and if so, what standards;
15        (viii) opportunities for coordination and cohesion 
16    with electric vehicle and electric vehicle charging 
17    equipment incentives established by any agency, 
18    department, board, or commission of the State, any other 
19    unit of government in the State, any national programs, or 
20    any unit of the federal government;
21        (ix) ideas for the development of online tools, 
22    applications, and data sharing that provide essential 
23    information to those charging electric vehicles, and 
24    enable an automated charging response to price signals, 
25    emission signals, real-time renewable generation 
26    production, and other Commission-approved or 
 
 
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1    customer-desired indicators of beneficial charging times; 
2    and
3        (x) customer education, outreach, and incentive 
4    programs that increase awareness of the programs and the 
5    benefits of transportation electrification, including 
6    direct outreach to eligible communities.
7    (e) Proceedings under this Section shall proceed according 
8to the rules provided by Article IX of the Public Utilities 
9Act. Information contained in the approved plan shall be 
10considered part of the record in any Commission proceeding 
11under Section 16-107.6 of the Public Utilities Act, provided 
12that a final order has not been entered prior to the initial 
13filing date.
14    (f) The utility shall file an update to the plan on July 1, 
152024 and every 3 years thereafter. This update shall describe 
16transportation investments made during the prior plan period, 
17investments planned for the following 24 months, and updates 
18to the information required by this Section. Beginning with 
19the first update, the    The utility shall develop the plan in 
20conjunction with the distribution system planning process 
21described in Section 16-105.17, including incorporation of 
22stakeholder feedback from that process.
23    (g) Within 35 days after the utility files its report, the 
24Commission shall, upon its own initiative, open an 
25investigation regarding the utility's plan update to 
26investigate whether the objectives described in this Section 
 
 
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1are being achieved. The Commission shall determine whether 
2investment targets should be increased based on achievement of 
3spending goals outlined in the Beneficial Electrification Plan 
4and consistency with outcomes directed in the plan stakeholder 
5workshop report. If the Commission finds, after notice and 
6hearing, that the utility's plan is materially deficient, the 
7Commission shall issue an order requiring the utility to 
8devise a corrective action plan, subject to Commission 
9approval, to bring the plan into compliance with the goals of 
10this Section. The Commission's order shall be entered within 
11270 days after the utility files its annual report. The 
12contents of a plan filed under this Section shall be available 
13for evidence in Commission proceedings. However, omission from 
14an approved plan shall not render any future utility 
15expenditure to be considered unreasonable or imprudent. The 
16Commission may, upon sufficient evidence, allow expenditures 
17that were not part of any particular distribution plan. The 
18Commission shall consider revenues from electric vehicles in 
19the utility's service territory in evaluating the retail rate 
20impact. The retail rate impact from the development of 
21electric vehicle infrastructure shall not exceed 1% per year 
22of the total annual revenue requirements of the utility.
23    (h) In meeting the requirements of this Section, the 
24utility, and beginning January 1, 2029 the Agency, shall 
25demonstrate efforts to increase the use of contractors and 
26electric vehicle charging station installers that meet 
 
 
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1multiple workforce equity actions, including, but not limited 
2to:
3        (1) the business is headquartered in or the person 
4    resides in an eligible community;
5        (2) the business is majority owned by eligible person 
6    or the contractor is an eligible person;
7        (3) the business or person is certified by another 
8    municipal, State, federal, or other certification for 
9    disadvantaged businesses;
10        (4) the business or person meets the eligibility 
11    criteria for a certification program such as:
12            (A) certified under Section 2 of the Business 
13        Enterprise for Minorities, Women, and Persons with 
14        Disabilities Act;
15            (B) certified by another municipal, State, 
16        federal, or other certification for disadvantaged 
17        businesses;
18            (C) submits an affidavit showing that the vendor 
19        meets the eligibility criteria for a certification 
20        program such as those in items (A) and (B);
21            (D) if the vendor is a nonprofit, meets any of the 
22        criteria in those in item (A), (B), or (C) with the 
23        exception that the nonprofit is not required to meet 
24        any criteria related to being a for-profit entity, or 
25        is controlled by a board of directors that consists of 
26        51% or greater individuals who are equity investment 
 
 
10400SB0025ham002- 79 -LRB104 07069 AAS 28576 a

1        eligible persons; or
2            (E) ensuring that program implementation 
3        contractors and electric vehicle charging station 
4        installers pay employees working on electric vehicle 
5        charging installations at or above the prevailing wage 
6        rate as published by the Department of Labor.
7    Utilities, and beginning January 1, 2029 the Agency, shall 
8establish reporting procedures for vendors that ensure 
9compliance with this subsection, but are structured to avoid, 
10wherever possible, placing an undue administrative burden on 
11vendors.
12    (i) Program data collection.
13        (1) In order to ensure that the benefits provided to 
14    Illinois residents and business by the clean energy 
15    economy are equitably distributed across the State, it is 
16    necessary to accurately measure the applicants and 
17    recipients of this Program. The purpose of this paragraph 
18    is to require the implementing utilities, and beginning 
19    January 1, 2029 the Agency, to collect all data from 
20    Program applicants and beneficiaries to track and improve 
21    equitable distribution of benefits across Illinois 
22    communities. The further purpose is to measure any 
23    potential impact of racial discrimination on the 
24    distribution of benefits and provide the utilities the 
25    information necessary to correct any discrimination 
26    through methods consistent with State and federal law.
 
 
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1        (2) The implementing utilities, and beginning January 
2    1, 2029 the Agency, shall collect demographic and 
3    geographic data for each applicant and each person or 
4    business awarded benefits or contracts under this Program.
5        (3) The implementing utilities, and beginning January 
6    1, 2029 the Agency, shall collect the following 
7    information from applicants and Program or procurement 
8    beneficiaries where applicable:
9            (A) demographic information, including racial or 
10        ethnic identity for real persons employed, contracted, 
11        or subcontracted through the program;
12            (B) demographic information, including racial or 
13        ethnic identity of business owners;
14            (C) geographic location of the residency of real 
15        persons or geographic location of the headquarters for 
16        businesses; and
17            (D) any other information necessary for the 
18        purpose of achieving the purpose of this paragraph.
19        (4) The utility, and beginning January 1, 2029 the 
20    Agency, shall publish, at least annually, aggregated 
21    information on the demographics of program and procurement 
22    applicants and beneficiaries. The utilities shall protect 
23    personal and confidential business information as 
24    necessary.
25        (5) The utilities, and beginning January 1, 2029 the 
26    Agency, shall conduct a regular review process to confirm 
 
 
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1    the accuracy of reported data.
2        (6) On a quarterly basis, utilities, and beginning 
3    January 1, 2029 the Agency, shall collect data necessary 
4    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, and beginning January 1, 2029 the 
10    Agency, shall report annually to the Illinois Commerce 
11    Commission and the General Assembly on how hiring, 
12    contracting, job training, and other practices related to 
13    its Beneficial electrification programs enhance the 
14    diversity of vendors working on such programs. These 
15    reports must include data on vendor and employee 
16    diversity.
17    (j) The provisions of this Section are severable under 
18Section 1.31 of the Statute on Statutes. 
19    (k) The utilities' Beneficial Electrification Plans under 
20this Section shall end no later than December 31, 2028. 
21Beginning January 1, 2029, the beneficial electrification 
22programs described in this Section shall be administered by 
23the Environmental Protection Agency. The Agency shall have 
24broad authority to provide grants and other forms of financial 
25assistance to develop and implement beneficial electrification 
26programs that achieve the goals described in paragraphs (1) 
 
 
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1through (8) of subsection (d) of this Section, and that may 
2include, but are not limited to, initiatives as described in 
3items (i) through (x) of subsection (d) of this Section.
4    (l) No later than March 1, 2028, the Agency shall publish a 
5draft 3-year Beneficial Electrification Plan for the 
6implementation of its beneficial electrification programs and 
7solicit comments and input from interested stakeholders, 
8including through public workshops, on the design of the 
9programs. As part of the Plan development process, the Agency 
10shall strive to meaningfully engage members and 
11representatives of equity investment eligible communities at 
12the outset of Plan development, prior to the publication of 
13the draft Plan, and during the comment and input process. The 
14Plan shall take into consideration lessons learned from the 
15implementation of utility Beneficial Electrification Plans 
16described in this Section. Within 180 days after the 
17publication of its draft Beneficial Electrification Plan, the 
18Agency shall publish a final Plan that is designed and 
19reasonably expected to achieve the goals described in 
20paragraphs (1) through (8) of subsection (d) of this Section.
21    (m) Funds shall be made available from the Electric 
22Vehicle and Charging Fund to the Agency to provide grants and 
23other forms of financial assistance and administer beneficial 
24electrification programs. Subject to appropriation, the annual 
25budget for Agency-administered beneficial electrification 
26programs shall be equivalent to the average annual budget of 
 
 
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1programs administered by the utilities under this Section for 
2the years 2026 through 2028.    
3(Source: P.A. 102-662, eff. 9-15-21; 102-820, eff. 5-13-22; 
4103-154, eff. 6-30-23.)
 
5    Section 90-7. The Energy Transition Act is amended by 
6changing Section 5-40 as follows:
 
7    (20 ILCS 730/5-40)
8    (Section scheduled to be repealed on September 15, 2045)
9    Sec. 5-40. Illinois Climate Works Preapprenticeship 
10Program. 
11    (a) Subject to appropriation, the Department shall 
12develop, and through Regional Administrators administer, the 
13Illinois Climate Works Preapprenticeship Program. The goal of 
14the Illinois Climate Works Preapprenticeship Program is to 
15create a network of hubs throughout the State that will 
16recruit, prescreen, and provide preapprenticeship skills 
17training, for which participants may attend free of charge and 
18receive a stipend, to create a qualified, diverse pipeline of 
19workers who are prepared for careers in the construction and 
20building trades and clean energy jobs opportunities therein. 
21Upon completion of the Illinois Climate Works 
22Preapprenticeship Program, the candidates will be connected to 
23and prepared to successfully complete an apprenticeship 
24program.
 
 
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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    Section 90-10. The Illinois Finance Authority Act is 
13amended by adding Section 850-20 as follows:
 
14    (20 ILCS 3501/850-20 new)
15    Sec. 850-20. Thermal Energy Network Revolving Loan and 
16Financial Assistance Program.
17    (a) As used in this Section:
18    "Program" means the Thermal Energy Network Revolving Loan 
19and Financial Assistance Program established under this 
20Section.    
21    "Thermal energy network" means all real estate, fixtures, 
22and personal property operated, owned, used, or to be used for 
23in connection with or to facilitate a community-scale 
24distribution infrastructure project that transfers heat into 
 
 
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1and out of buildings using non-combusting thermal energy, 
2sourced from zero-emission technologies, including geothermal 
3energy, for the purpose of reducing emissions. "Thermal energy 
4network" includes, but is not limited to, real estate, 
5fixtures, and personal property that is operated, owned, or 
6used by multiple parties and community geothermal systems.    
7    (b) In its role as the Climate Bank for the State, the 
8Authority may, subject to available funding, establish and 
9administer a Thermal Energy Network Revolving Loan and 
10Financial Assistance Program. The Program shall provide access 
11to capital for thermal energy network projects that take into 
12consideration the risks involved in the development of shared 
13heating and cooling systems and the required coordination 
14among multiple customers, as well as the benefits of enabling 
15low-cost decarbonization of residential, commercial, and 
16industrial buildings and processes. The Program may provide 
17loans, grants, or other financial assistance for thermal 
18energy network projects.
19    (c) The Authority may establish internal accounts 
20necessary to administer the Program, identify sources of 
21public and private funding and financial capital, and develop 
22any requirements or agreements necessary to successfully 
23execute the Program.
24    (d) The Authority shall coordinate and enter into any 
25necessary agreements with the Illinois Commerce Commission to 
26(i) develop and offer funding and financing to thermal energy 
 
 
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1network pilot projects approved by the Commission under 
2subsection (a) of Section 8-513 of the Public Utilities Act, 
3(ii) receive funds as necessary and as approved by the 
4Commission under subsection (b) of Section 8-513 of the Public 
5Utilities Act, and (iii) establish any requirements necessary 
6to ensure compliance with the objectives of any federal 
7funding sources secured to support the Program.
8    (e) All repayments of loans or other financial assistance 
9made under the Program shall be used or leveraged to provide 
10additional capital to thermal energy network pilot projects 
11that support the clean energy goals of the State, in 
12coordination with any rules established by the Illinois 
13Commerce Commission.
14    (f) The Authority may adopt any resolutions, plans, or 
15rules and fix, determine, charge, or collect any fees, 
16charges, costs, and expenses necessary to administer the 
17Program under this Section.
 
18    Section 90-11. The Illinois Power Agency Act is amended by 
19changing Sections 1-10, 1-20, 1-56, 1-75, and 1-125 as 
20follows:
 
21    (20 ILCS 3855/1-10)
22    Sec. 1-10. Definitions. 
23    "Agency" means the Illinois Power Agency.
24    "Agency loan agreement" means any agreement pursuant to 
 
 
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1which the Illinois Finance Authority agrees to loan the 
2proceeds of revenue bonds issued with respect to a project to 
3the Agency upon terms providing for loan repayment 
4installments at least sufficient to pay when due all principal 
5of, interest and premium, if any, on those revenue bonds, and 
6providing for maintenance, insurance, and other matters in 
7respect of the project.
8    "Authority" means the Illinois Finance Authority.
9    "Brownfield site photovoltaic project" means photovoltaics 
10that are either:
11        (1) interconnected to an electric utility as defined 
12    in this Section, a municipal utility as defined in this 
13    Section, a public utility as defined in Section 3-105 of 
14    the Public Utilities Act, or an electric cooperative as 
15    defined in Section 3-119 of the Public Utilities Act and 
16    located at a site that is regulated by any of the following 
17    entities under the following programs:
18            (A) the United States Environmental Protection 
19        Agency under the federal Comprehensive Environmental 
20        Response, Compensation, and Liability Act of 1980, as 
21        amended;
22            (B) the United States Environmental Protection 
23        Agency under the Corrective Action Program of the 
24        federal Resource Conservation and Recovery Act, as 
25        amended;
26            (C) the Illinois Environmental Protection Agency 
 
 
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1        under the Illinois Site Remediation Program; or
2            (D) the Illinois Environmental Protection Agency 
3        under the Illinois Solid Waste Program; or 
4        (2) located at the site of a coal mine that has 
5    permanently ceased coal production, permanently halted any 
6    re-mining operations, and is no longer accepting any coal 
7    combustion residues; has both completed all clean-up and 
8    remediation obligations under the federal Surface Mining 
9    and Reclamation Act of 1977 and all applicable Illinois 
10    rules and any other clean-up, remediation, or ongoing 
11    monitoring to safeguard the health and well-being of the 
12    people of the State of Illinois, as well as demonstrated 
13    compliance with all applicable federal and State 
14    environmental rules and regulations, including, but not 
15    limited, to 35 Ill. Adm. Code Part 845 and any rules for 
16    historic fill of coal combustion residuals, including any 
17    rules finalized in Subdocket A of Illinois Pollution 
18    Control Board docket R2020-019. 
19    "Clean coal facility" means an electric generating 
20facility that uses primarily coal as a feedstock and that 
21captures and sequesters carbon dioxide emissions at the 
22following levels: at least 50% of the total carbon dioxide 
23emissions that the facility would otherwise emit if, at the 
24time construction commences, the facility is scheduled to 
25commence operation before 2016, at least 70% of the total 
26carbon dioxide emissions that the facility would otherwise 
 
 
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1emit if, at the time construction commences, the facility is 
2scheduled to commence operation during 2016 or 2017, and at 
3least 90% of the total carbon dioxide emissions that the 
4facility would otherwise emit if, at the time construction 
5commences, the facility is scheduled to commence operation 
6after 2017. The power block of the clean coal facility shall 
7not exceed allowable emission rates for sulfur dioxide, 
8nitrogen oxides, carbon monoxide, particulates and mercury for 
9a natural gas-fired combined-cycle facility the same size as 
10and in the same location as the clean coal facility at the time 
11the clean coal facility obtains an approved air permit. All 
12coal used by a clean coal facility shall have high volatile 
13bituminous rank and greater than 1.7 pounds of sulfur per 
14million Btu content, unless the clean coal facility does not 
15use gasification technology and was operating as a 
16conventional coal-fired electric generating facility on June 
171, 2009 (the effective date of Public Act 95-1027). 
18    "Clean coal SNG brownfield facility" means a facility that 
19(1) has commenced construction by July 1, 2015 on an urban 
20brownfield site in a municipality with at least 1,000,000 
21residents; (2) uses a gasification process to produce 
22substitute natural gas; (3) uses coal as at least 50% of the 
23total feedstock over the term of any sourcing agreement with a 
24utility and the remainder of the feedstock may be either 
25petroleum coke or coal, with all such coal having a high 
26bituminous rank and greater than 1.7 pounds of sulfur per 
 
 
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1million Btu content unless the facility reasonably determines 
2that it is necessary to use additional petroleum coke to 
3deliver additional consumer savings, in which case the 
4facility shall use coal for at least 35% of the total feedstock 
5over the term of any sourcing agreement; and (4) captures and 
6sequesters at least 85% of the total carbon dioxide emissions 
7that the facility would otherwise emit. 
8    "Clean coal SNG facility" means a facility that uses a 
9gasification process to produce substitute natural gas, that 
10sequesters at least 90% of the total carbon dioxide emissions 
11that the facility would otherwise emit, that uses at least 90% 
12coal as a feedstock, with all such coal having a high 
13bituminous rank and greater than 1.7 pounds of sulfur per 
14million Btu content, and that has a valid and effective permit 
15to construct emission sources and air pollution control 
16equipment and approval with respect to the federal regulations 
17for Prevention of Significant Deterioration of Air Quality 
18(PSD) for the plant pursuant to the federal Clean Air Act; 
19provided, however, a clean coal SNG brownfield facility shall 
20not be a clean coal SNG facility. 
21    "Clean energy" means energy generation that is 90% or 
22greater free of carbon dioxide emissions. 
23    "Commission" means the Illinois Commerce Commission.
24    "Community renewable generation project" means an electric 
25generating facility that: 
26        (1) is powered by wind, solar thermal energy, 
 
 
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1    photovoltaic cells or panels, biodiesel, crops and 
2    untreated and unadulterated organic waste biomass, and 
3    hydropower that does not involve new construction of dams; 
4        (2) is interconnected at the distribution system level 
5    of an electric utility as defined in this Section, a 
6    municipal utility as defined in this Section that owns or 
7    operates electric distribution facilities, a public 
8    utility as defined in Section 3-105 of the Public 
9    Utilities Act, or an electric cooperative, as defined in 
10    Section 3-119 of the Public Utilities Act;
11        (3) credits the value of electricity generated by the 
12    facility to the subscribers of the facility; and
13        (4) is limited in nameplate capacity to less than or 
14    equal to 5,000 kilowatts.
15    "Costs incurred in connection with the development and 
16construction of a facility" means:
17        (1) the cost of acquisition of all real property, 
18    fixtures, and improvements in connection therewith and 
19    equipment, personal property, and other property, rights, 
20    and easements acquired that are deemed necessary for the 
21    operation and maintenance of the facility;
22        (2) financing costs with respect to bonds, notes, and 
23    other evidences of indebtedness of the Agency;
24        (3) all origination, commitment, utilization, 
25    facility, placement, underwriting, syndication, credit 
26    enhancement, and rating agency fees;
 
 
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1        (4) engineering, design, procurement, consulting, 
2    legal, accounting, title insurance, survey, appraisal, 
3    escrow, trustee, collateral agency, interest rate hedging, 
4    interest rate swap, capitalized interest, contingency, as 
5    required by lenders, and other financing costs, and other 
6    expenses for professional services; and
7        (5) the costs of plans, specifications, site study and 
8    investigation, installation, surveys, other Agency costs 
9    and estimates of costs, and other expenses necessary or 
10    incidental to determining the feasibility of any project, 
11    together with such other expenses as may be necessary or 
12    incidental to the financing, insuring, acquisition, and 
13    construction of a specific project and starting up, 
14    commissioning, and placing that project in operation. 
15    "Delivery services" has the same definition as found in 
16Section 16-102 of the Public Utilities Act. 
17    "Delivery year" means the consecutive 12-month period 
18beginning June 1 of a given year and ending May 31 of the 
19following year. 
20    "Department" means the Department of Commerce and Economic 
21Opportunity.
22    "Director" means the Director of the Illinois Power 
23Agency.
24    "Demand response Demand-response" means measures that 
25decrease peak electricity demand or shift demand from peak to 
26off-peak periods.
 
 
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1    "Distributed renewable energy generation device" means a 
2device that is:
3        (1) powered by wind, solar thermal energy, 
4    photovoltaic cells or panels, biodiesel, crops and 
5    untreated and unadulterated organic waste biomass, tree 
6    waste, and hydropower that does not involve new 
7    construction of dams, waste heat to power systems, or 
8    qualified combined heat and power systems; 
9        (2) interconnected at the distribution system level of 
10    either an electric utility as defined in this Section, a 
11    municipal utility as defined in this Section that owns or 
12    operates electric distribution facilities, or a rural 
13    electric cooperative as defined in Section 3-119 of the 
14    Public Utilities Act; 
15        (3) located on the customer side of the customer's 
16    electric meter and is primarily used to offset that 
17    customer's electricity load; and
18        (4) (blank). 
19    "Energy efficiency" means measures that reduce the amount 
20of electricity or natural gas consumed in order to achieve a 
21given end use. "Energy efficiency" includes voltage 
22optimization measures that optimize the voltage at points on 
23the electric distribution voltage system and thereby reduce 
24electricity consumption by electric customers' end use 
25devices. "Energy efficiency" also includes measures that 
26reduce the total Btus of electricity, natural gas, and other 
 
 
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1fuels needed to meet the end use or uses. 
2    "Energy storage system" has the meaning given to that term 
3in Section 16-135 of the Public Utilities Act. "Energy storage 
4system" does not include technologies that require combustion.
5    "Energy storage resources" means the operational output or 
6capabilities of energy storage systems. "Energy storage 
7resources" includes, but is not limited to, energy, capacity, 
8and energy storage credits.    
9    "Electric utility" has the same definition as found in 
10Section 16-102 of the Public Utilities Act.
11    "Equity investment eligible community" or "eligible 
12community" are synonymous and mean the geographic areas 
13throughout Illinois which would most benefit from equitable 
14investments by the State designed to combat discrimination. 
15Specifically, the eligible communities shall be defined as the 
16following areas:
17        (1) R3 Areas as established pursuant to Section 10-40 
18    of the Cannabis Regulation and Tax Act, where residents 
19    have historically been excluded from economic 
20    opportunities, including opportunities in the energy 
21    sector; and
22        (2) environmental justice communities, as defined by 
23    the Illinois Power Agency pursuant to the Illinois Power 
24    Agency Act, where residents have historically been subject 
25    to disproportionate burdens of pollution, including 
26    pollution from the energy sector.
 
 
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1    "Equity eligible persons" or "eligible persons" means 
2persons who would most benefit from equitable investments by 
3the State designed to combat discrimination, specifically:
4        (1) persons who graduate from or are current or former 
5    participants in the Clean Jobs Workforce Network Program, 
6    the Clean Energy Contractor Incubator Program, the 
7    Illinois Climate Works Preapprenticeship Program, 
8    Returning Residents Clean Jobs Training Program, or the 
9    Clean Energy Primes Contractor Accelerator Program, and 
10    the solar training pipeline and multi-cultural jobs 
11    program created in paragraphs (1) and (3) of subsection 
12    (a) (a)(1) and (a)(3) of Section 16-108.12 16-208.12 of 
13    the Public Utilities Act;
14        (2) persons who are graduates of or currently enrolled 
15    in the foster care system;
16        (3) persons who were formerly incarcerated;
17        (4) persons whose primary residence is in an equity 
18    investment eligible community.
19    "Equity eligible contractor" means a business that is 
20majority-owned by eligible persons, or a nonprofit or 
21cooperative that is majority-governed by eligible persons, or 
22is a natural person that is an eligible person offering 
23personal services as an independent contractor. 
24    "Facility" means an electric generating unit or a 
25co-generating unit that produces electricity along with 
26related equipment necessary to connect the facility to an 
 
 
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1electric transmission or distribution system.
2    "General contractor" means the entity or organization with 
3main responsibility for the building of a construction project 
4and who is the party signing the prime construction contract 
5for the project. 
6    "Governmental aggregator" means one or more units of local 
7government that individually or collectively procure 
8electricity to serve residential retail electrical loads 
9located within its or their jurisdiction.
10    "High voltage direct current converter station" means the 
11collection of equipment that converts direct current energy 
12from a high voltage direct current transmission line into 
13alternating current using Voltage Source Conversion technology 
14and that is interconnected with transmission or distribution 
15assets located in Illinois.
16    "High voltage direct current renewable energy credit" 
17means a renewable energy credit associated with a renewable 
18energy resource where the renewable energy resource has 
19entered into a contract to transmit the energy associated with 
20such renewable energy credit over high voltage direct current 
21transmission facilities. 
22    "High voltage direct current transmission facilities" 
23means the collection of installed equipment that converts 
24alternating current energy in one location to direct current 
25and transmits that direct current energy to a high voltage 
26direct current converter station using Voltage Source 
 
 
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1Conversion technology. "High voltage direct current 
2transmission facilities" includes the high voltage direct 
3current converter station itself and associated high voltage 
4direct current transmission lines. Notwithstanding the 
5preceding, after September 15, 2021 (the effective date of 
6Public Act 102-662), an otherwise qualifying collection of 
7equipment does not qualify as high voltage direct current 
8transmission facilities unless (1) its developer entered into 
9a project labor agreement, is capable of transmitting 
10electricity at 525kv with an Illinois converter station 
11located and interconnected in the region of the PJM 
12Interconnection, LLC, and the system does not operate as a 
13public utility, as that term is defined in Section 3-105 of the 
14Public Utilities Act, serving more than 100,000 customers as 
15of January 1, 2021; or (2) its developer has entered into a 
16project labor agreement prior to construction, the project is 
17capable of transmitting electricity at 525 kilovolts or above, 
18and the project has a converter station that is located in this 
19State or in a state adjacent to this State and is 
20interconnected to PJM Interconnection, LLC, the Midcontinent 
21Independent System Operator, Inc., or their successor.
22    "Hydropower" means any method of electricity generation or 
23storage that results from the flow of water, including 
24impoundment facilities, diversion facilities, and pumped 
25storage facilities. 
26    "Index price" means the real-time energy settlement price 
 
 
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1at the applicable Illinois trading hub, such as PJM-NIHUB or 
2MISO-IL, for a given settlement period.
3    "Indexed renewable energy credit" means a tradable credit 
4that represents the environmental attributes of one megawatt 
5hour of energy produced from a renewable energy resource, the 
6price of which shall be calculated by subtracting the strike 
7price offered by a new utility-scale wind project or a new 
8utility-scale photovoltaic project from the index price in a 
9given settlement period. 
10    "Indexed renewable energy credit counterparty" has the 
11same meaning as "public utility" as defined in Section 3-105 
12of the Public Utilities Act.
13    "Local government" means a unit of local government as 
14defined in Section 1 of Article VII of the Illinois 
15Constitution.
16    "Modernized" or "retooled" means the construction, repair, 
17maintenance, or significant expansion of turbines and existing 
18hydropower dams. 
19    "Municipality" means a city, village, or incorporated 
20town.
21    "Municipal utility" means a public utility owned and 
22operated by any subdivision or municipal corporation of this 
23State. 
24    "Nameplate capacity" means the aggregate inverter 
25nameplate capacity in kilowatts AC. 
26    "Person" means any natural person, firm, partnership, 
 
 
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1corporation, either domestic or foreign, company, association, 
2limited liability company, joint stock company, or association 
3and includes any trustee, receiver, assignee, or personal 
4representative thereof.
5    "Project" means the planning, bidding, and construction of 
6a facility.
7    "Project labor agreement" means a pre-hire collective 
8bargaining agreement that covers all terms and conditions of 
9employment on a specific construction project and must include 
10the following:
11        (1) provisions establishing the minimum hourly wage 
12    for each class of labor organization employee;
13        (2) provisions establishing the benefits and other 
14    compensation for each class of labor organization 
15    employee;
16        (3) provisions establishing that no strike or disputes 
17    will be engaged in by the labor organization employees;
18        (4) provisions establishing that no lockout or 
19    disputes will be engaged in by the general contractor 
20    building the project; and
21        (5) provisions for minorities and women, as defined 
22    under the Business Enterprise for Minorities, Women, and 
23    Persons with Disabilities Act, setting forth goals for 
24    apprenticeship hours to be performed by minorities and 
25    women and setting forth goals for total hours to be 
26    performed by underrepresented minorities and women.
 
 
10400SB0025ham002- 104 -LRB104 07069 AAS 28576 a

1    A labor organization and the general contractor building 
2the project shall have the authority to include other terms 
3and conditions as they deem necessary. 
4    "Public utility" has the same definition as found in 
5Section 3-105 of the Public Utilities Act.
6    "Qualified combined heat and power systems" means systems 
7that, either simultaneously or sequentially, produce 
8electricity and useful thermal energy from a single fuel 
9source. Such systems are eligible for "renewable energy 
10credits" in an amount equal to its total energy output where a 
11renewable fuel is consumed or in an amount equal to the net 
12reduction in nonrenewable fuel consumed on a total energy 
13output basis. 
14    "Real property" means any interest in land together with 
15all structures, fixtures, and improvements thereon, including 
16lands under water and riparian rights, any easements, 
17covenants, licenses, leases, rights-of-way, uses, and other 
18interests, together with any liens, judgments, mortgages, or 
19other claims or security interests related to real property.
20    "Renewable energy credit" means a tradable credit that 
21represents the environmental attributes of one megawatt hour 
22of energy produced from a renewable energy resource.
23    "Renewable energy resources" includes energy and its 
24associated renewable energy credit or renewable energy credits 
25from wind, solar thermal energy, photovoltaic cells and 
26panels, biodiesel, anaerobic digestion, crops and untreated 
 
 
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1and unadulterated organic waste biomass, and hydropower that 
2does not involve new construction of dams, waste heat to power 
3systems, or qualified combined heat and power systems. For 
4purposes of this Act, landfill gas produced in the State is 
5considered a renewable energy resource. "Renewable energy 
6resources" does not include the incineration or burning of 
7tires, garbage, general household, institutional, and 
8commercial waste, industrial lunchroom or office waste, 
9landscape waste, railroad crossties, utility poles, or 
10construction or demolition debris, other than untreated and 
11unadulterated waste wood. "Renewable energy resources" also 
12includes high voltage direct current renewable energy credits 
13and the associated energy converted to alternating current by 
14a high voltage direct current converter station to the extent 
15that: (1) the generator of such renewable energy resource 
16contracted with a third party to transmit the energy over the 
17high voltage direct current transmission facilities, and (2) 
18the third-party contracting for delivery of renewable energy 
19resources over the high voltage direct current transmission 
20facilities have ownership rights over the unretired associated 
21high voltage direct current renewable energy credit. 
22    "Retail customer" has the same definition as found in 
23Section 16-102 of the Public Utilities Act. 
24    "Revenue bond" means any bond, note, or other evidence of 
25indebtedness issued by the Authority, the principal and 
26interest of which is payable solely from revenues or income 
 
 
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1derived from any project or activity of the Agency.
2    "Sequester" means permanent storage of carbon dioxide by 
3injecting it into a saline aquifer, a depleted gas reservoir, 
4or an oil reservoir, directly or through an enhanced oil 
5recovery process that may involve intermediate storage, 
6regardless of whether these activities are conducted by a 
7clean coal facility, a clean coal SNG facility, a clean coal 
8SNG brownfield facility, or a party with which a clean coal 
9facility, clean coal SNG facility, or clean coal SNG 
10brownfield facility has contracted for such purposes. 
11    "Service area" has the same definition as found in Section 
1216-102 of the Public Utilities Act. 
13    "Settlement period" means the period of time utilized by 
14MISO and PJM and their successor organizations as the basis 
15for settlement calculations in the real-time energy market. 
16    "Sourcing agreement" means (i) in the case of an electric 
17utility, an agreement between the owner of a clean coal 
18facility and such electric utility, which agreement shall have 
19terms and conditions meeting the requirements of paragraph (3) 
20of subsection (d) of Section 1-75, (ii) in the case of an 
21alternative retail electric supplier, an agreement between the 
22owner of a clean coal facility and such alternative retail 
23electric supplier, which agreement shall have terms and 
24conditions meeting the requirements of Section 16-115(d)(5) of 
25the Public Utilities Act, and (iii) in case of a gas utility, 
26an agreement between the owner of a clean coal SNG brownfield 
 
 
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1facility and the gas utility, which agreement shall have the 
2terms and conditions meeting the requirements of subsection 
3(h-1) of Section 9-220 of the Public Utilities Act. 
4    "Strike price" means a contract price for energy and 
5renewable energy credits from a new utility-scale wind project 
6or a new utility-scale photovoltaic project. 
7    "Subscriber" means a person who (i) takes delivery service 
8from an electric utility, and (ii) has a subscription of no 
9less than 200 watts to a community renewable generation 
10project that is located in the electric utility's service 
11area. No subscriber's subscriptions may total more than 40% of 
12the nameplate capacity of an individual community renewable 
13generation project. Entities that are affiliated by virtue of 
14a common parent shall not represent multiple subscriptions 
15that total more than 40% of the nameplate capacity of an 
16individual community renewable generation project.
17    "Subscription" means an interest in a community renewable 
18generation project expressed in kilowatts, which is sized 
19primarily to offset part or all of the subscriber's 
20electricity usage. 
21    "Substitute natural gas" or "SNG" means a gas manufactured 
22by gasification of hydrocarbon feedstock, which is 
23substantially interchangeable in use and distribution with 
24conventional natural gas. 
25    "Total resource cost test" or "TRC test" means a standard 
26that is met if, for an investment in energy efficiency or 
 
 
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1demand-response measures, the benefit-cost ratio is greater 
2than one. The benefit-cost ratio is the ratio of the net 
3present value of the total benefits of the program to the net 
4present value of the total costs as calculated over the 
5lifetime of the measures. A total resource cost test compares 
6the sum of avoided electric utility costs, representing the 
7benefits that accrue to the system and the participant in the 
8delivery of those efficiency measures and including avoided 
9costs associated with reduced use of natural gas or other 
10fuels, avoided costs associated with reduced water 
11consumption, and avoided costs associated with reduced 
12operation and maintenance costs, and avoided societal costs 
13associated with reductions in greenhouse gas emissions, as 
14well as other quantifiable societal benefits, to the sum of 
15all incremental costs of end-use measures that are implemented 
16due to the program (including both utility and participant 
17contributions), plus costs to administer, deliver, and 
18evaluate each demand-side program, to quantify the net savings 
19obtained by substituting the demand-side program for supply 
20resources. The societal costs associated with greenhouse gas 
21emissions shall be $200 per short ton, expressed in 2025 
22dollars or the most recently approved estimate developed by 
23the federal government using a real discount rate consistent 
24with long-term Treasury bond yields, whichever is greater. 
25Changes in greenhouse gas emissions due to changes in 
26electricity consumption shall be estimated using long-run 
 
 
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1marginal emissions rates developed by the National Renewable 
2Energy Laboratory's Cambium model or other Illinois-specific 
3modeling of comparable analytical rigor. In calculating 
4avoided costs of power and energy that an electric utility 
5would otherwise have had to acquire, reasonable estimates 
6shall be included of financial costs likely to be imposed by 
7future regulations and legislation on emissions of greenhouse 
8gases. In discounting future societal costs and benefits for 
9the purpose of calculating net present values, a societal 
10discount rate based on actual, long-term Treasury bond yields 
11should be used. Notwithstanding anything to the contrary, the 
12TRC test shall not include or take into account a calculation 
13of market price suppression effects or demand reduction 
14induced price effects. 
15    "Utility-scale solar project" means an electric generating 
16facility that:
17        (1) generates electricity using photovoltaic cells; 
18    and
19        (2) has a nameplate capacity that is greater than 
20    5,000 kilowatts alternating current (AC). 
21    "Utility-scale wind project" means an electric generating 
22facility that:
23        (1) generates electricity using wind; and
24        (2) has a nameplate capacity that is greater than 
25    5,000 kilowatts. 
26    "Waste Heat to Power Systems" means systems that capture 
 
 
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1and generate electricity from energy that would otherwise be 
2lost to the atmosphere without the use of additional fuel. 
3    "Zero emission credit" means a tradable credit that 
4represents the environmental attributes of one megawatt hour 
5of energy produced from a zero emission facility.
6    "Zero emission facility" means a facility that: (1) is 
7fueled by nuclear power; and (2) is interconnected with PJM 
8Interconnection, LLC or the Midcontinent Independent System 
9Operator, Inc., or their successors.
10(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23; 
11103-380, eff. 1-1-24.)
 
12    (20 ILCS 3855/1-20)
13    Sec. 1-20. General powers and duties of the Agency. 
14    (a) The Agency is authorized to do each of the following:
15        (1) Develop electricity procurement plans to ensure 
16    adequate, reliable, affordable, efficient, and 
17    environmentally sustainable electric service at the lowest 
18    total cost over time, taking into account any benefits of 
19    price stability, for electric utilities that on December 
20    31, 2005 provided electric service to at least 100,000 
21    customers in Illinois and for small multi-jurisdictional 
22    electric utilities that (A) on December 31, 2005 served 
23    less than 100,000 customers in Illinois and (B) request a 
24    procurement plan for their Illinois jurisdictional load. 
25    Except as provided in paragraph (1.5) of this subsection 
 
 
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1    (a), the electricity procurement plans shall be updated on 
2    an annual basis and shall include electricity generated 
3    from renewable resources sufficient to achieve the 
4    standards specified in this Act. Beginning with the 
5    delivery year commencing June 1, 2017, develop procurement 
6    plans to include zero emission credits generated from zero 
7    emission facilities sufficient to achieve the standards 
8    specified in this Act. Beginning with the delivery year 
9    commencing on June 1, 2022, the Agency is authorized to 
10    develop carbon mitigation credit procurement plans to 
11    include carbon mitigation credits generated from 
12    carbon-free energy resources sufficient to achieve the 
13    standards specified in this Act. 
14        (1.5) Develop a long-term renewable resources 
15    procurement plan in accordance with subsection (c) of 
16    Section 1-75 of this Act for renewable energy credits in 
17    amounts sufficient to achieve the standards specified in 
18    this Act for delivery years commencing June 1, 2017 and 
19    for the programs and renewable energy credits specified in 
20    Section 1-56 of this Act. Electricity procurement plans 
21    for delivery years commencing after May 31, 2017, shall 
22    not include procurement of renewable energy resources. 
23        (2) Conduct competitive procurement processes to 
24    procure the supply resources identified in the electricity 
25    procurement plan, pursuant to Section 16-111.5 of the 
26    Public Utilities Act, and, for the delivery year 
 
 
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1    commencing June 1, 2017, conduct procurement processes to 
2    procure zero emission credits from zero emission 
3    facilities, under subsection (d-5) of Section 1-75 of this 
4    Act. For the delivery year commencing June 1, 2022, the 
5    Agency is authorized to conduct procurement processes to 
6    procure carbon mitigation credits from carbon-free energy 
7    resources, under subsection (d-10) of Section 1-75 of this 
8    Act. 
9        (2.5) Beginning with the procurement for the 2017 
10    delivery year, conduct competitive procurement processes 
11    and implement programs to procure renewable energy credits 
12    identified in the long-term renewable resources 
13    procurement plan developed and approved under subsection 
14    (c) of Section 1-75 of this Act and Section 16-111.5 of the 
15    Public Utilities Act. 
16        (2.10) Oversee the procurement by electric utilities 
17    that served more than 300,000 customers in this State as 
18    of January 1, 2019 of renewable energy credits from new 
19    renewable energy facilities to be installed, along with 
20    energy storage facilities, at or adjacent to the sites of 
21    electric generating facilities that burned coal as their 
22    primary fuel source as of January 1, 2016 in accordance 
23    with subsection (c-5) of Section 1-75 of this Act.
24        (2.15) Oversee the procurement by electric utilities 
25    of renewable energy credits from newly modernized or 
26    retooled hydropower dams or dams that have been converted 
 
 
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1    to support hydropower generation. 
2        (3) Develop electric generation and co-generation 
3    facilities that use indigenous coal or renewable 
4    resources, or both, financed with bonds issued by the 
5    Illinois Finance Authority.
6        (4) Supply electricity from the Agency's facilities at 
7    cost to one or more of the following: municipal electric 
8    systems, governmental aggregators, or rural electric 
9    cooperatives in Illinois.
10        (5) Develop a long-term energy storage resources 
11    procurement plan and conduct competitive procurement 
12    processes in accordance with subsection (d-20) of Section 
13    1-75.    
14    (b) Except as otherwise limited by this Act, the Agency 
15has all of the powers necessary or convenient to carry out the 
16purposes and provisions of this Act, including without 
17limitation, each of the following:
18        (1) To have a corporate seal, and to alter that seal at 
19    pleasure, and to use it by causing it or a facsimile to be 
20    affixed or impressed or reproduced in any other manner.
21        (2) To use the services of the Illinois Finance 
22    Authority necessary to carry out the Agency's purposes.
23        (3) To negotiate and enter into loan agreements and 
24    other agreements with the Illinois Finance Authority.
25        (4) To obtain and employ personnel and hire 
26    consultants that are necessary to fulfill the Agency's 
 
 
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1    purposes, and to make expenditures for that purpose within 
2    the appropriations for that purpose.
3        (5) To purchase, receive, take by grant, gift, devise, 
4    bequest, or otherwise, lease, or otherwise acquire, own, 
5    hold, improve, employ, use, and otherwise deal in and 
6    with, real or personal property whether tangible or 
7    intangible, or any interest therein, within the State.
8        (6) To acquire real or personal property, whether 
9    tangible or intangible, including without limitation 
10    property rights, interests in property, franchises, 
11    obligations, contracts, and debt and equity securities, 
12    and to do so by the exercise of the power of eminent domain 
13    in accordance with Section 1-21; except that any real 
14    property acquired by the exercise of the power of eminent 
15    domain must be located within the State.
16        (7) To sell, convey, lease, exchange, transfer, 
17    abandon, or otherwise dispose of, or mortgage, pledge, or 
18    create a security interest in, any of its assets, 
19    properties, or any interest therein, wherever situated.
20        (8) To purchase, take, receive, subscribe for, or 
21    otherwise acquire, hold, make a tender offer for, vote, 
22    employ, sell, lend, lease, exchange, transfer, or 
23    otherwise dispose of, mortgage, pledge, or grant a 
24    security interest in, use, and otherwise deal in and with, 
25    bonds and other obligations, shares, or other securities 
26    (or interests therein) issued by others, whether engaged 
 
 
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1    in a similar or different business or activity.
2        (9) To make and execute agreements, contracts, and 
3    other instruments necessary or convenient in the exercise 
4    of the powers and functions of the Agency under this Act, 
5    including contracts with any person, including personal 
6    service contracts, or with any local government, State 
7    agency, or other entity; and all State agencies and all 
8    local governments are authorized to enter into and do all 
9    things necessary to perform any such agreement, contract, 
10    or other instrument with the Agency. No such agreement, 
11    contract, or other instrument shall exceed 40 years.
12        (10) To lend money, invest and reinvest its funds in 
13    accordance with the Public Funds Investment Act, and take 
14    and hold real and personal property as security for the 
15    payment of funds loaned or invested.
16        (11) To borrow money at such rate or rates of interest 
17    as the Agency may determine, issue its notes, bonds, or 
18    other obligations to evidence that indebtedness, and 
19    secure any of its obligations by mortgage or pledge of its 
20    real or personal property, machinery, equipment, 
21    structures, fixtures, inventories, revenues, grants, and 
22    other funds as provided or any interest therein, wherever 
23    situated.
24        (12) To enter into agreements with the Illinois 
25    Finance Authority to issue bonds whether or not the income 
26    therefrom is exempt from federal taxation.
 
 
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1        (13) To procure insurance against any loss in 
2    connection with its properties or operations in such 
3    amount or amounts and from such insurers, including the 
4    federal government, as it may deem necessary or desirable, 
5    and to pay any premiums therefor.
6        (14) To negotiate and enter into agreements with 
7    trustees or receivers appointed by United States 
8    bankruptcy courts or federal district courts or in other 
9    proceedings involving adjustment of debts and authorize 
10    proceedings involving adjustment of debts and authorize 
11    legal counsel for the Agency to appear in any such 
12    proceedings.
13        (15) To file a petition under Chapter 9 of Title 11 of 
14    the United States Bankruptcy Code or take other similar 
15    action for the adjustment of its debts.
16        (16) To enter into management agreements for the 
17    operation of any of the property or facilities owned by 
18    the Agency.
19        (17) To enter into an agreement to transfer and to 
20    transfer any land, facilities, fixtures, or equipment of 
21    the Agency to one or more municipal electric systems, 
22    governmental aggregators, or rural electric agencies or 
23    cooperatives, for such consideration and upon such terms 
24    as the Agency may determine to be in the best interest of 
25    the residents of Illinois.
26        (18) To enter upon any lands and within any building 
 
 
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1    whenever in its judgment it may be necessary for the 
2    purpose of making surveys and examinations to accomplish 
3    any purpose authorized by this Act.
4        (19) To maintain an office or offices at such place or 
5    places in the State as it may determine.
6        (20) To request information, and to make any inquiry, 
7    investigation, survey, or study that the Agency may deem 
8    necessary to enable it effectively to carry out the 
9    provisions of this Act.
10        (21) To accept and expend appropriations.
11        (22) To engage in any activity or operation that is 
12    incidental to and in furtherance of efficient operation to 
13    accomplish the Agency's purposes, including hiring 
14    employees that the Director deems essential for the 
15    operations of the Agency.
16        (23) To adopt, revise, amend, and repeal rules with 
17    respect to its operations, properties, and facilities as 
18    may be necessary or convenient to carry out the purposes 
19    of this Act, subject to the provisions of the Illinois 
20    Administrative Procedure Act and Sections 1-22 and 1-35 of 
21    this Act.
22        (24) To establish and collect charges and fees as 
23    described in this Act.
24        (25) To conduct competitive gasification feedstock 
25    procurement processes to procure the feedstocks for the 
26    clean coal SNG brownfield facility in accordance with the 
 
 
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1    requirements of Section 1-78 of this Act. 
2        (26) To review, revise, and approve sourcing 
3    agreements and mediate and resolve disputes between gas 
4    utilities and the clean coal SNG brownfield facility 
5    pursuant to subsection (h-1) of Section 9-220 of the 
6    Public Utilities Act. 
7        (27) To request, review and accept proposals, execute 
8    contracts, purchase renewable energy credits and otherwise 
9    dedicate funds from the Illinois Power Agency Renewable 
10    Energy Resources Fund to create and carry out the 
11    objectives of the Illinois Solar for All Program in 
12    accordance with Section 1-56 of this Act. 
13        (28) To ensure Illinois residents and business benefit 
14    from programs administered by the Agency and are properly 
15    protected from any deceptive or misleading marketing 
16    practices by participants in the Agency's programs and 
17    procurements. 
18    (c) In conducting the procurement of electricity or other 
19products, beginning January 1, 2022, the Agency shall not 
20procure any products or services from persons or organizations 
21that are in violation of the Displaced Energy Workers Bill of 
22Rights, as provided under the Energy Community Reinvestment 
23Act at the time of the procurement event or fail to comply the 
24labor standards established in subparagraph (Q) of paragraph 
25(1) of subsection (c) of Section 1-75. 
26(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
 
 
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1    (20 ILCS 3855/1-56)
2    Sec. 1-56. Illinois Power Agency Renewable Energy 
3Resources Fund; Illinois Solar for All Program.
4    (a) The Illinois Power Agency Renewable Energy Resources 
5Fund is created as a special fund in the State treasury.
6    (b) The Illinois Power Agency Renewable Energy Resources 
7Fund shall be administered by the Agency as described in this 
8subsection (b), provided that the changes to this subsection 
9(b) made by Public Act 99-906 shall not interfere with 
10existing contracts under this Section. 
11        (1) The Illinois Power Agency Renewable Energy 
12    Resources Fund shall be used to purchase renewable energy 
13    credits according to any approved procurement plan 
14    developed by the Agency prior to June 1, 2017.
15        (2) The Illinois Power Agency Renewable Energy 
16    Resources Fund shall also be used to create the Illinois 
17    Solar for All Program, which provides incentives for 
18    low-income distributed generation and community solar 
19    projects, and other associated approved expenditures. The 
20    objectives of the Illinois Solar for All Program are to 
21    bring photovoltaics to low-income communities in this 
22    State in a manner that maximizes the development of new 
23    photovoltaic generating facilities, to create a long-term, 
24    low-income solar marketplace throughout this State, to 
25    integrate, through interaction with stakeholders, with 
 
 
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1    existing energy efficiency initiatives, and to minimize 
2    administrative costs. The Illinois Solar for All Program 
3    shall be implemented in a manner that seeks to minimize 
4    administrative costs, and maximize efficiencies and 
5    synergies available through coordination with similar 
6    initiatives, including the Adjustable Block program 
7    described in subparagraphs (K) through (M) of paragraph 
8    (1) of subsection (c) of Section 1-75, energy efficiency 
9    programs, job training programs, and community action 
10    agencies , and agencies that administer the Low-Income 
11    Home Energy Assistance Program. The Agency shall strive to 
12    ensure that renewable energy credits procured through the 
13    Illinois Solar for All Program and each of its subprograms 
14    are purchased from projects across the breadth of 
15    low-income and environmental justice communities in 
16    Illinois, including both urban and rural communities, are 
17    not concentrated in a few communities, and do not exclude 
18    particular low-income or environmental justice 
19    communities. The Agency shall include a description of its 
20    proposed approach to the design, administration, 
21    implementation and evaluation of the Illinois Solar for 
22    All Program, as part of the long-term renewable resources 
23    procurement plan authorized by subsection (c) of Section 
24    1-75 of this Act, and the program shall be designed to grow 
25    the low-income solar market. The Agency or utility, as 
26    applicable, shall purchase renewable energy credits from 
 
 
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1    the (i) photovoltaic distributed renewable energy 
2    generation projects and (ii) community solar projects that 
3    are procured under procurement processes authorized by the 
4    long-term renewable resources procurement plans approved 
5    by the Commission.
6        The Illinois Solar for All Program shall include the 
7    program offerings described in subparagraphs (A) through 
8    (E) of this paragraph (2), which the Agency shall 
9    implement through contracts with third-party providers 
10    and, subject to appropriation, pay the approximate amounts 
11    identified using monies available in the Illinois Power 
12    Agency Renewable Energy Resources Fund. Each contract that 
13    provides for the installation of solar facilities shall 
14    provide that the solar facilities will produce energy and 
15    economic benefits, at a level determined by the Agency to 
16    be reasonable, for the participating low-income customers. 
17    The monies available in the Illinois Power Agency 
18    Renewable Energy Resources Fund and not otherwise 
19    committed to contracts executed under subsection (i) of 
20    this Section, as well as, in the case of the programs 
21    described under subparagraphs (A) through (E) of this 
22    paragraph (2), funding authorized pursuant to subparagraph 
23    (O) of paragraph (1) of subsection (c) of Section 1-75 of 
24    this Act, shall initially be allocated among the programs 
25    described in this paragraph (2), as follows: 35% of these 
26    funds shall be allocated to programs described in 
 
 
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1    subparagraphs (A) and (E) of this paragraph (2), 40% of 
2    these funds shall be allocated to programs described in 
3    subparagraph (B) of this paragraph (2), and 25% of these 
4    funds shall be allocated to programs described in 
5    subparagraph (C) of this paragraph (2). The allocation of 
6    funds among subparagraphs (A), (B), (C), and (E) of this 
7    paragraph (2) may be changed if the Agency, after 
8    receiving input through a stakeholder process, determines 
9    incentives in subparagraph subparagraphs (A), (B), (C), or 
10    (E) of this paragraph (2) have not been adequately 
11    subscribed to fully utilize available Illinois Solar for 
12    All Program funds.
13        Contracts that will be paid with funds in the Illinois 
14    Power Agency Renewable Energy Resources Fund shall be 
15    executed by the Agency. Contracts that will be paid with 
16    funds collected by an electric utility shall be executed 
17    by the electric utility.
18        Contracts under the Illinois Solar for All Program 
19    shall include an approach, as set forth in the long-term 
20    renewable resources procurement plans, to ensure the 
21    wholesale market value of the energy is credited to 
22    participating low-income customers or organizations and to 
23    ensure tangible economic benefits flow directly to program 
24    participants, except in the case of low-income 
25    multi-family housing where the low-income customer does 
26    not directly pay for energy. Priority shall be given to 
 
 
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1    projects that demonstrate meaningful involvement of 
2    low-income community members in designing the initial 
3    proposals. Acceptable proposals to implement projects must 
4    demonstrate the applicant's ability to conduct initial 
5    community outreach, education, and recruitment of 
6    low-income participants in the community. Projects 
7    submitted by approved vendors must either comply with the 
8    minimum equity standard set forth in subsection (c-10) of 
9    Section 1-75 of this Act or must include job training 
10    opportunities if available, with the specific level of 
11    trainee usage to be determined through the Agency's 
12    long-term renewable resources procurement plan, and the 
13    Illinois Solar for All Program Administrator shall 
14    coordinate with the job training programs described in 
15    paragraph (1) of subsection (a) of Section 16-108.12 of 
16    the Public Utilities Act and in the Energy Transition Act. 
17        The Agency shall make every effort to ensure that 
18    small and emerging businesses, particularly those located 
19    in low-income and environmental justice communities, are 
20    able to participate in the Illinois Solar for All Program. 
21    These efforts may include, but shall not be limited to, 
22    proactive support from the program administrator, 
23    different or preferred access to subprograms and 
24    administrator-identified customers or grassroots 
25    education provider-identified customers, and different 
26    incentive levels. The Agency shall report on progress and 
 
 
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1    barriers to participation of small and emerging businesses 
2    in the Illinois Solar for All Program at least once a year. 
3    The report shall be made available on the Agency's website 
4    and, in years when the Agency is updating its long-term 
5    renewable resources procurement plan, included in that 
6    Plan. 
7            (A) Low-income single-family and small multifamily 
8        solar incentive. This program will provide incentives 
9        to low-income customers, either directly or through 
10        solar providers, to increase the participation of 
11        low-income households in photovoltaic on-site 
12        distributed generation at residential buildings 
13        containing one to 4 units. Companies participating in 
14        this program that install solar panels shall commit to 
15        meeting a minimum equity standard or hiring job 
16        trainees for a portion of their low-income 
17        installations, and an administrator shall facilitate 
18        partnering the companies that install solar panels 
19        with entities that provide solar panel installation 
20        job training. It is a goal of this program that a 
21        minimum of 25% of the incentives for this program be 
22        allocated to projects located within environmental 
23        justice communities. Contracts entered into under this 
24        paragraph may be entered into with an entity that will 
25        develop and administer the program and shall also 
26        include contracts for renewable energy credits from 
 
 
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1        the photovoltaic distributed generation that is the 
2        subject of the program, as set forth in the long-term 
3        renewable resources procurement plan. Additionally:
4                (i) The Agency shall reserve a portion of this 
5            program for projects that promote energy 
6            sovereignty through ownership of projects by 
7            low-income households, not-for-profit 
8            organizations providing services to low-income 
9            households, affordable housing owners, community 
10            cooperatives, or community-based limited liability 
11            companies providing services to low-income 
12            households. Projects that feature energy ownership 
13            should ensure that local people have control of 
14            the project and reap benefits from the project 
15            over and above energy bill savings. The Agency may 
16            consider the inclusion of projects that promote 
17            ownership over time or that involve partial 
18            project ownership by communities, as promoting 
19            energy sovereignty. Incentives for projects that 
20            promote energy sovereignty may be higher than 
21            incentives for equivalent projects that do not 
22            promote energy sovereignty under this same 
23            program.
24                (ii) Through its long-term renewable resources 
25            procurement plan, the Agency shall consider 
26            additional program and contract requirements to 
 
 
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1            ensure faithful compliance by applicants 
2            benefiting from preferences for projects 
3            designated to promote energy sovereignty. The 
4            Agency shall make every effort to enable solar 
5            providers already participating in the Adjustable 
6            Block program Program under subparagraph (K) of 
7            paragraph (1) of subsection (c) of Section 1-75 of 
8            this Act, and particularly solar providers 
9            developing projects under item (i) of subparagraph 
10            (K) of paragraph (1) of subsection (c) of Section 
11            1-75 of this Act to easily participate in the 
12            Low-Income Distributed Generation Incentive 
13            program described under this subparagraph (A), and 
14            vice versa. This effort may include, but shall not 
15            be limited to, utilizing similar or the same 
16            application systems and processes, utilizing    
17            similar or the same forms and formats of 
18            communication, and providing active outreach to 
19            companies participating in one program but not the 
20            other. The Agency shall report on efforts made to 
21            encourage this cross-participation in its 
22            long-term renewable resources procurement plan. 
23                (iii) To maximize equitable participation in 
24            this program and overcome challenges facing the 
25            development of residential solar projects, the 
26            Agency may propose a payment structure for 
 
 
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1            contracts executed pursuant to this subparagraph 
2            (A) under which applicant firms are advanced 
3            capital that is disbursed after contract execution 
4            but before the contracted project's energization, 
5            upon a demonstration of qualification or need 
6            under criteria established by the Agency that are 
7            focused on supporting the small and emerging 
8            businesses and the businesses that most acutely 
9            face barriers to capital access, which severely 
10            limits the businesses' participation in the 
11            program described in this subparagraph (A). The 
12            amount or percentage of capital advanced before 
13            project energization shall be designed to overcome 
14            the barriers in access to capital that are faced 
15            by an applicant. The amount or percentage of 
16            advanced capital may vary under this subparagraph 
17            (A) by an applicant's demonstration of need, with 
18            such levels to be established through the 
19            Long-Term Renewable Resources Procurement Plan and 
20            any application requirements or evaluation 
21            criteria developed under that Plan.    
22            (B) Low-Income Community Solar Project Initiative. 
23        Incentives shall be offered to low-income customers, 
24        either directly or through developers, to increase the 
25        participation of low-income subscribers of community 
26        solar projects. The developer of each project shall 
 
 
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1        identify its partnership with community stakeholders 
2        regarding the location, development, and participation 
3        in the project, provided that nothing shall preclude a 
4        project from including an anchor tenant that does not 
5        qualify as low-income. Companies participating in this 
6        program that develop or install solar projects shall 
7        commit to meeting a minimum equity standard or to    
8        hiring job trainees for a portion of their low-income 
9        installations, and an administrator shall facilitate 
10        partnering the companies that install solar projects 
11        with entities that provide solar installation and 
12        related job training. It is a goal of this program that 
13        a minimum of 25% of the incentives for this program be 
14        allocated to community photovoltaic projects in 
15        environmental justice communities. The Agency shall 
16        reserve a portion of this program for projects that 
17        promote energy sovereignty through ownership of 
18        projects by low-income households, not-for-profit 
19        organizations providing services to low-income 
20        households, affordable housing owners, or 
21        community-based limited liability companies providing 
22        services to low-income households. Projects that 
23        feature energy ownership should ensure that local 
24        people have control of the project and reap benefits 
25        from the project over and above energy bill savings. 
26        The Agency may consider the inclusion of projects that 
 
 
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1        promote ownership over time or that involve partial 
2        project ownership by communities, as promoting energy 
3        sovereignty. Incentives for projects that promote 
4        energy sovereignty may be higher than incentives for 
5        equivalent projects that do not promote energy 
6        sovereignty under this same program. Contracts entered 
7        into under this paragraph may be entered into with 
8        developers and shall also include contracts for 
9        renewable energy credits related to the program.
10            (C) Incentives for non-profits and public 
11        facilities. Under this program funds shall be used to 
12        support on-site photovoltaic distributed renewable 
13        energy generation devices to serve the load associated 
14        with not-for-profit customers and to support 
15        photovoltaic distributed renewable energy generation 
16        that uses photovoltaic technology to serve the load 
17        associated with public sector customers taking service 
18        at public buildings. Master-metered multifamily 
19        buildings that primarily house income-eligible 
20        residents may qualify under this subparagraph (C). 
21        Nonprofits and public facilities that can demonstrate 
22        that the nonprofit or public facility serves 
23        income-qualified or environmental justice communities 
24        may potentially qualify for the program, regardless of 
25        physical location. Qualification may be determined 
26        using the same procedures applied to critical service 
 
 
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1        provider requests for the purpose of establishing 
2        project eligibility in areas that are not designated 
3        as income-eligible or environmental justice 
4        communities. Companies participating in this program 
5        that develop or install solar projects shall commit to 
6        meeting a minimum equity standard or to hiring job 
7        trainees for a portion of their low-income 
8        installations, and an administrator shall facilitate 
9        partnering the companies that install solar projects 
10        with entities that provide solar installation and 
11        related job training. Through its long-term renewable 
12        resources procurement plan, the Agency shall consider 
13        additional program and contract requirements to ensure 
14        faithful compliance by applicants benefiting from 
15        preferences for projects designated to promote energy 
16        sovereignty. It is a goal of this program that at least 
17        25% of the incentives for this program be allocated to 
18        projects located in environmental justice communities. 
19        Contracts entered into under this paragraph may be 
20        entered into with an entity that will develop and 
21        administer the program or with developers and shall 
22        also include contracts for renewable energy credits 
23        related to the program.
24            (D) (Blank). 
25            (E) Low-income large multifamily solar incentive. 
26        This program shall provide incentives to low-income 
 
 
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1        customers, either directly or through solar providers, 
2        to increase the participation of low-income households 
3        in photovoltaic on-site distributed generation at 
4        residential buildings with 5 or more units. Companies 
5        participating in this program that develop or install 
6        solar projects shall commit to meeting a minimum 
7        equity standard or to hiring job trainees for a 
8        portion of their low-income installations, and an 
9        administrator shall facilitate partnering the 
10        companies that install solar projects with entities 
11        that provide solar installation and related job 
12        training. It is a goal of this program that a minimum 
13        of 25% of the incentives for this program be allocated 
14        to projects located within environmental justice 
15        communities. The Agency shall reserve a portion of 
16        this program for projects that promote energy 
17        sovereignty through ownership of projects by 
18        low-income households, not-for-profit organizations 
19        providing services to low-income households, 
20        affordable housing owners, or community-based limited 
21        liability companies providing services to low-income 
22        households. Projects that feature energy ownership 
23        should ensure that local people have control of the 
24        project and reap benefits from the project over and 
25        above energy bill savings. The Agency may consider the 
26        inclusion of projects that promote ownership over time 
 
 
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1        or that involve partial project ownership by 
2        communities, as promoting energy sovereignty. 
3        Incentives for projects that promote energy 
4        sovereignty may be higher than incentives for 
5        equivalent projects that do not promote energy 
6        sovereignty under this same program. 
7        The requirement that a qualified person, as defined in 
8    paragraph (1) of subsection (i) of this Section, install 
9    photovoltaic devices does not apply to the Illinois Solar 
10    for All Program described in this subsection (b).
11        In addition to the programs outlined in paragraphs (A) 
12    through (E), the Agency and other parties may propose 
13    additional programs through the long-term renewable 
14    resources procurement plan Long-Term Renewable Resources 
15    Procurement Plan developed and approved under paragraph 
16    (5) of subsection (b) of Section 16-111.5 of the Public 
17    Utilities Act. Additional programs may target market 
18    segments not specified above and may also include 
19    incentives targeted to increase the uptake of 
20    nonphotovoltaic technologies by low-income customers, 
21    including energy storage paired with photovoltaics, if the 
22    Commission determines that the Illinois Solar for All 
23    Program would provide greater benefits to the public 
24    health and well-being of low-income residents through also 
25    supporting that additional program versus supporting 
26    programs already authorized. 
 
 
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1        (3) Costs associated with the Illinois Solar for All 
2    Program and its components described in paragraph (2) of 
3    this subsection (b), including, but not limited to, costs 
4    associated with procuring experts, consultants, and the 
5    program administrator referenced in this subsection (b) 
6    and related incremental costs, costs related to income 
7    verification and facilitating customer participation in 
8    the program through referrals and other methods, costs 
9    related to obtaining feedback on the program from parties 
10    that do not have a financial interest, and costs related 
11    to the evaluation of the Illinois Solar for All Program, 
12    may be paid for using monies in the Illinois Power Agency 
13    Renewable Energy Resources Fund, and funds allocated 
14    pursuant to subparagraph (O) of paragraph (1) of 
15    subsection (c) of Section 1-75, but the Agency or program 
16    administrator shall strive to minimize costs in the 
17    implementation of the program. The Agency or contracting 
18    electric utility shall purchase renewable energy credits 
19    from generation that is the subject of a contract under 
20    subparagraphs (A) through (E) of paragraph (2) of this 
21    subsection (b), and may pay for such renewable energy 
22    credits through an upfront payment per installed kilowatt 
23    of nameplate capacity paid once the device is 
24    interconnected at the distribution system level of the 
25    interconnecting utility and verified as energized. Unless 
26    otherwise provided in the Agency's long-term renewable 
 
 
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1    resources procurement plan, payments Payments for 
2    renewable energy credits shall be in exchange for all 
3    renewable energy credits generated by the system during 
4    the first 15 years of operation and shall be structured to 
5    overcome barriers to participation in the solar market by 
6    the low-income community. The incentives provided for in 
7    this Section may be implemented through the pricing of 
8    renewable energy credits where the prices paid for the 
9    credits are higher than the prices from programs offered 
10    under subsection (c) of Section 1-75 of this Act to 
11    account for the additional capital necessary to 
12    successfully access targeted market segments. The Agency 
13    or contracting electric utility shall retire any renewable 
14    energy credits purchased under this program and the 
15    credits shall count toward the obligation under subsection 
16    (c) of Section 1-75 of this Act for the electric utility to 
17    which the project is interconnected, if applicable.
18        The Agency shall direct that up to 5% of the funds 
19    available under the Illinois Solar for All Program to 
20    community-based groups and other qualifying organizations 
21    to assist in community-driven education efforts related to 
22    the Illinois Solar for All Program, including general 
23    energy education, job training program outreach efforts, 
24    and other activities deemed to be qualified by the Agency. 
25    Grassroots education funding shall not be used to support 
26    the marketing by solar project development firms and 
 
 
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1    organizations, unless such education provides equal 
2    opportunities for all applicable firms and organizations.
3        The Agency may direct up to 25% of the funds currently 
4    allocated to subparagraphs (A), (C), and (E) of paragraph 
5    (2) toward the Illinois Storage for All Program, which 
6    provides incentives through grants, rebates, or other 
7    incentives to encourage development of energy storage 
8    colocated with photovoltaic distributed renewable energy 
9    generation devices developed through the Illinois Solar 
10    for All Program. Any unused Storage for All funds during a 
11    program year may be reallocated to other Solar for All 
12    Program projects that are waitlisted or otherwise not 
13    selected due to funding limitation per the Agency's 
14    defined process. The Illinois Storage for All Program 
15    shall be available to current and future participants of 
16    the low-income single-family and multifamily subprogram 
17    described in subparagraphs (A) and (E) of paragraph (2), 
18    and the subprogram for nonprofit and public facilities 
19    described in subparagraph (C) of paragraph (2). If 
20    developed, the Illinois Storage for All Program may be 
21    designed to support community energy resilience, disaster 
22    preparedness, and energy bill reductions, particularly for 
23    residents of low-income and environmental justice 
24    communities. The Agency may propose the funding amount, 
25    structure, and details of the Illinois Storage for All 
26    Program in the Agency's long-term renewable resources 
 
 
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1    procurement plan described in subsection (c) of Section 
2    1-75 of this Act and Section 16-111.5 of the Public 
3    Utilities Act, or through its energy storage resources 
4    procurement plan described in subsection (d-20) of Section 
5    1-75 of this Act. As part of the development of its initial 
6    energy storage resources procurement plan, the Agency 
7    shall engage stakeholders in the development of the 
8    Illinois Storage for All Program, including, but not 
9    limited to, members of the Illinois Commission on 
10    Environmental Justice described in Section 10 of the 
11    Environmental Justice Act, representatives of approved 
12    vendors participating in the Illinois Solar for All 
13    Program, representatives of community-based 
14    organizations, and members of the Illinois Solar for All 
15    Stakeholder Advisory Group. The stakeholder process shall 
16    include, but not be limited to, an exploration of how to 
17    ensure that the distributed storage will be accessible to 
18    income-qualified households with zero upfront costs and in 
19    coordination with job training programs, as well as how 
20    the program may be supported by other programs or 
21    initiatives to maximize storage benefits and limit 
22    double-counting of incentives.    
23        (4) The Agency shall, consistent with the requirements 
24    of this subsection (b), propose the Illinois Solar for All 
25    Program terms, conditions, and requirements, including the 
26    prices to be paid for renewable energy credits, and which 
 
 
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1    prices may be determined through a formula, through the 
2    development, review, and approval of the Agency's 
3    long-term renewable resources procurement plan described 
4    in subsection (c) of Section 1-75 of this Act and Section 
5    16-111.5 of the Public Utilities Act. In the course of the 
6    Commission proceeding initiated to review and approve the 
7    plan, including the Illinois Solar for All Program 
8    proposed by the Agency, a party may propose an additional 
9    low-income solar or solar incentive program, or 
10    modifications to the programs proposed by the Agency, and 
11    the Commission may approve an additional program, or 
12    modifications to the Agency's proposed program, if the 
13    additional or modified program more effectively maximizes 
14    the benefits to low-income customers after taking into 
15    account all relevant factors, including, but not limited 
16    to, the extent to which a competitive market for 
17    low-income solar has developed. Following the Commission's 
18    approval of the Illinois Solar for All Program, the Agency 
19    or a party may propose adjustments to the program terms, 
20    conditions, and requirements, including the price offered 
21    to new systems, to ensure the long-term viability and 
22    success of the program. The Commission shall review and 
23    approve any modifications to the program through the plan 
24    revision process described in Section 16-111.5 of the 
25    Public Utilities Act.
26        (5) The Agency shall issue a request for 
 
 
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1    qualifications for a third-party program administrator or 
2    administrators to administer all or a portion of the 
3    Illinois Solar for All Program. The third-party program 
4    administrator shall be chosen through a competitive bid 
5    process based on selection criteria and requirements 
6    developed by the Agency, including, but not limited to, 
7    experience in administering low-income energy programs and 
8    overseeing statewide clean energy or energy efficiency 
9    services. If the Agency retains a program administrator or 
10    administrators to implement all or a portion of the 
11    Illinois Solar for All Program, each administrator shall 
12    periodically submit reports to the Agency and Commission 
13    for each program that it administers, at appropriate 
14    intervals to be identified by the Agency in its long-term 
15    renewable resources procurement plan, subject to 
16    Commission approval, provided that the reporting interval 
17    is at least an annual period quarterly. The third-party 
18    program administrator may be, but need not be, the same 
19    administrator as for the Adjustable Block program 
20    described in subparagraphs (K) through (M) of paragraph 
21    (1) of subsection (c) of Section 1-75. The Agency, through 
22    its long-term renewable resources procurement plan 
23    approval process, shall also determine if individual 
24    subprograms of the Illinois Solar for All Program are 
25    better served by a different or separate Program 
26    Administrator.
 
 
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1        The third-party administrator's responsibilities 
2    shall also include facilitating placement for graduates of 
3    Illinois-based renewable energy-specific job training 
4    programs, including the Clean Jobs Workforce Network 
5    Program and the Illinois Climate Works Preapprenticeship 
6    Program administered by the Department of Commerce and 
7    Economic Opportunity and programs administered under 
8    Section 16-108.12 of the Public Utilities Act. To increase 
9    the uptake of trainees by participating firms, the 
10    administrator shall also develop a web-based clearinghouse 
11    for information available to both job training program 
12    graduates and firms participating, directly or indirectly, 
13    in Illinois solar incentive programs. The program 
14    administrator shall also coordinate its activities with 
15    entities implementing electric and natural gas 
16    income-qualified energy efficiency programs, including 
17    customer referrals to and from such programs, and connect 
18    prospective low-income solar customers with any existing 
19    deferred maintenance programs where applicable. 
20        (6) The long-term renewable resources procurement plan 
21    shall also provide for an independent evaluation of the 
22    Illinois Solar for All Program. At least every 5 2 years, 
23    the Agency shall select an independent evaluator to review 
24    and report on the Illinois Solar for All Program and the 
25    performance of the third-party program administrator of 
26    the Illinois Solar for All Program. The evaluation shall 
 
 
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1    be based on objective criteria developed through a public 
2    stakeholder process. The process shall include feedback 
3    and participation from Illinois Solar for All Program 
4    stakeholders, including participants and organizations in 
5    environmental justice and historically underserved 
6    communities. The report shall include a summary of the 
7    evaluation of the Illinois Solar for All Program based on 
8    the stakeholder developed objective criteria. The report 
9    shall include the number of projects installed; the total 
10    installed capacity in kilowatts; the average cost per 
11    kilowatt of installed capacity to the extent reasonably 
12    obtainable by the Agency; the number of jobs or job 
13    opportunities created; economic, social, and environmental 
14    benefits created; and the total administrative costs 
15    expended by the Agency and program administrator to 
16    implement and evaluate the program. The report shall be 
17    prepared at least every 2 years and shall be delivered to 
18    the Commission and posted on the Agency's website, and 
19    shall be used, as needed, to revise the Illinois Solar for 
20    All Program. The Commission shall also consider the 
21    results of the evaluation as part of its review of the 
22    long-term renewable resources procurement plan under 
23    subsection (c) of Section 1-75 of this Act.
24        (7) If additional funding for the programs described 
25    in this subsection (b) is available under subsection (k) 
26    of Section 16-108 of the Public Utilities Act, then the 
 
 
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1    Agency shall submit a procurement plan to the Commission 
2    no later than September 1, 2018, that proposes how the 
3    Agency will procure programs on behalf of the applicable 
4    utility. After notice and hearing, the Commission shall 
5    approve, or approve with modification, the plan no later 
6    than November 1, 2018.
7        (8) As part of the development and update of the 
8    long-term renewable resources procurement plan authorized 
9    by subsection (c) of Section 1-75 of this Act, the Agency 
10    shall plan for: (A) actions to refer customers from the 
11    Illinois Solar for All Program to electric and natural gas 
12    income-qualified energy efficiency programs, and vice 
13    versa, with the goal of increasing participation in both 
14    of these programs; (B) effective procedures for data 
15    sharing, as needed, to effectuate referrals between the 
16    Illinois Solar for All Program and both electric and 
17    natural gas income-qualified energy efficiency programs, 
18    including sharing customer information directly with the 
19    utilities, as needed and appropriate; and (C) efforts to 
20    identify any existing deferred maintenance programs for 
21    which prospective Solar for All Program customers may be 
22    eligible and connect prospective customers for whom 
23    deferred maintenance is or may be a barrier to solar 
24    installation to those programs. 
25    Income verification for participation in the Illinois 
26Solar for All subprograms described in subparagraphs (A) and 
 
 
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1(C) of paragraph (2) may include pathways for verification 
2that rely on self-attestation by the applicant if the 
3applicant's residence is located within a low-income or 
4environmental justice community as defined in this subsection 
5(b). The Agency shall proactively explore approaches that make 
6the income verification process less burdensome for residents 
7of low-income or environmental justice communities, as defined 
8in this subsection (b).    
9    As used in this subsection (b), "low-income households" 
10means persons and families whose income does not exceed 80% of 
11area median income, adjusted for family size and revised every 
12year.
13    For the purposes of this subsection (b), the Agency shall 
14define "environmental justice community" based on the 
15methodologies and findings established by the Agency and the 
16Administrator for the Illinois Solar for All Program in its 
17initial long-term renewable resources procurement plan and as 
18updated by the Agency and the Administrator for the Illinois 
19Solar for All Program as part of the long-term renewable 
20resources procurement plan update. 
21    (b-5) After the receipt of all payments required by 
22Section 16-115D of the Public Utilities Act, no additional 
23funds shall be deposited into the Illinois Power Agency 
24Renewable Energy Resources Fund unless directed by order of 
25the Commission.
26    (b-10) After the receipt of all payments required by 
 
 
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1Section 16-115D of the Public Utilities Act and payment in 
2full of all contracts executed by the Agency under subsections 
3(b) and (i) of this Section, if the balance of the Illinois 
4Power Agency Renewable Energy Resources Fund is under $5,000, 
5then the Fund shall be inoperative and any remaining funds and 
6any funds submitted to the Fund after that date, shall be 
7transferred to the Supplemental Low-Income Energy Assistance 
8Fund for use in the Low-Income Home Energy Assistance Program, 
9as authorized by the Energy Assistance Act.
10    (b-15) The prevailing wage requirements set forth in the 
11Prevailing Wage Act apply to each project that is undertaken 
12pursuant to one or more of the programs of incentives and 
13initiatives described in subsection (b) of this Section and 
14for which a project application is submitted to the program 
15after June 30, 2023 (the effective date of Public Act 103-188)    
16this amendatory Act of the 103rd General Assembly, except (i) 
17projects that serve single-family or multi-family residential 
18buildings and (ii) projects with an aggregate capacity of less 
19than 100 kilowatts that serve houses of worship. The Agency 
20shall require verification that all construction performed on 
21a project by the renewable energy credit delivery contract 
22holder, its contractors, or its subcontractors relating to the 
23construction of the facility is performed by workers receiving 
24an amount for that work that is greater than or equal to the 
25general prevailing rate of wages as that term is defined in the 
26Prevailing Wage Act, and the Agency may adjust renewable 
 
 
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1energy credit prices to account for increased labor costs.
2    In this subsection (b-15), "house of worship" has the 
3meaning given in subparagraph (Q) of paragraph (1) of 
4subsection (c) of Section 1-75. 
5    (c) (Blank).
6    (d) (Blank).
7    (e) All renewable energy credits procured using monies 
8from the Illinois Power Agency Renewable Energy Resources Fund 
9shall be permanently retired.
10    (f) The selection of one or more third-party program 
11managers or administrators, the selection of the independent 
12evaluator, and the procurement processes described in this 
13Section are exempt from the requirements of the Illinois 
14Procurement Code, under Section 20-10 of that Code.
15    (g) All disbursements from the Illinois Power Agency 
16Renewable Energy Resources Fund shall be made only upon 
17warrants of the Comptroller drawn upon the Treasurer as 
18custodian of the Fund upon vouchers signed by the Director or 
19by the person or persons designated by the Director for that 
20purpose. The Comptroller is authorized to draw the warrant 
21upon vouchers so signed. The Treasurer shall accept all 
22warrants so signed and shall be released from liability for 
23all payments made on those warrants.
24    (h) The Illinois Power Agency Renewable Energy Resources 
25Fund shall not be subject to sweeps, administrative charges, 
26or chargebacks, including, but not limited to, those 
 
 
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1authorized under Section 8h of the State Finance Act, that 
2would in any way result in the transfer of any funds from this 
3Fund to any other fund of this State or in having any such 
4funds utilized for any purpose other than the express purposes 
5set forth in this Section.
6    (h-5) The Agency may assess fees to each bidder to recover 
7the costs incurred in connection with a procurement process 
8held under this Section. Fees collected from bidders shall be 
9deposited into the Illinois Power Agency Renewable Energy 
10Resources Fund. 
11    (i) Supplemental procurement process.
12        (1) Within 90 days after June 30, 2014 (the effective 
13    date of Public Act 98-672), the Agency shall develop a 
14    one-time supplemental procurement plan limited to the 
15    procurement of renewable energy credits, if available, 
16    from new or existing photovoltaics, including, but not 
17    limited to, distributed photovoltaic generation. Nothing 
18    in this subsection (i) requires procurement of wind 
19    generation through the supplemental procurement.
20        Renewable energy credits procured from new 
21    photovoltaics, including, but not limited to, distributed 
22    photovoltaic generation, under this subsection (i) must be 
23    procured from devices installed by a qualified person. In 
24    its supplemental procurement plan, the Agency shall 
25    establish contractually enforceable mechanisms for 
26    ensuring that the installation of new photovoltaics is 
 
 
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1    performed by a qualified person.
2        For the purposes of this paragraph (1), "qualified 
3    person" means a person who performs installations of 
4    photovoltaics, including, but not limited to, distributed 
5    photovoltaic generation, and who: (A) has completed an 
6    apprenticeship as a journeyman electrician from a United 
7    States Department of Labor registered electrical 
8    apprenticeship and training program and received a 
9    certification of satisfactory completion; or (B) does not 
10    currently meet the criteria under clause (A) of this 
11    paragraph (1), but is enrolled in a United States 
12    Department of Labor registered electrical apprenticeship 
13    program, provided that the person is directly supervised 
14    by a person who meets the criteria under clause (A) of this 
15    paragraph (1); or (C) has obtained one of the following 
16    credentials in addition to attesting to satisfactory 
17    completion of at least 5 years or 8,000 hours of 
18    documented hands-on electrical experience: (i) a North 
19    American Board of Certified Energy Practitioners (NABCEP) 
20    Installer Certificate for Solar PV; (ii) an Underwriters 
21    Laboratories (UL) PV Systems Installer Certificate; (iii) 
22    an Electronics Technicians Association, International 
23    (ETAI) Level 3 PV Installer Certificate; or (iv) an 
24    Associate in Applied Science degree from an Illinois 
25    Community College Board approved community college program 
26    in renewable energy or a distributed generation 
 
 
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1    technology.
2        For the purposes of this paragraph (1), "directly 
3    supervised" means that there is a qualified person who 
4    meets the qualifications under clause (A) of this 
5    paragraph (1) and who is available for supervision and 
6    consultation regarding the work performed by persons under 
7    clause (B) of this paragraph (1), including a final 
8    inspection of the installation work that has been directly 
9    supervised to ensure safety and conformity with applicable 
10    codes.
11        For the purposes of this paragraph (1), "install" 
12    means the major activities and actions required to 
13    connect, in accordance with applicable building and 
14    electrical codes, the conductors, connectors, and all 
15    associated fittings, devices, power outlets, or 
16    apparatuses mounted at the premises that are directly 
17    involved in delivering energy to the premises' electrical 
18    wiring from the photovoltaics, including, but not limited 
19    to, to distributed photovoltaic generation. 
20        The renewable energy credits procured pursuant to the 
21    supplemental procurement plan shall be procured using up 
22    to $30,000,000 from the Illinois Power Agency Renewable 
23    Energy Resources Fund. The Agency shall not plan to use 
24    funds from the Illinois Power Agency Renewable Energy 
25    Resources Fund in excess of the monies on deposit in such 
26    fund or projected to be deposited into such fund. The 
 
 
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1    supplemental procurement plan shall ensure adequate, 
2    reliable, affordable, efficient, and environmentally 
3    sustainable renewable energy resources (including credits) 
4    at the lowest total cost over time, taking into account 
5    any benefits of price stability.
6        To the extent available, 50% of the renewable energy 
7    credits procured from distributed renewable energy 
8    generation shall come from devices of less than 25 
9    kilowatts in nameplate capacity. Procurement of renewable 
10    energy credits from distributed renewable energy 
11    generation devices shall be done through multi-year 
12    contracts of no less than 5 years. The Agency shall create 
13    credit requirements for counterparties. In order to 
14    minimize the administrative burden on contracting 
15    entities, the Agency shall solicit the use of third 
16    parties to aggregate distributed renewable energy. These 
17    third parties shall enter into and administer contracts 
18    with individual distributed renewable energy generation 
19    device owners. An individual distributed renewable energy 
20    generation device owner shall have the ability to measure 
21    the output of his or her distributed renewable energy 
22    generation device.
23        In developing the supplemental procurement plan, the 
24    Agency shall hold at least one workshop open to the public 
25    within 90 days after June 30, 2014 (the effective date of 
26    Public Act 98-672) and shall consider any comments made by 
 
 
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1    stakeholders or the public. Upon development of the 
2    supplemental procurement plan within this 90-day period, 
3    copies of the supplemental procurement plan shall be 
4    posted and made publicly available on the Agency's and 
5    Commission's websites. All interested parties shall have 
6    14 days following the date of posting to provide comment 
7    to the Agency on the supplemental procurement plan. All 
8    comments submitted to the Agency shall be specific, 
9    supported by data or other detailed analyses, and, if 
10    objecting to all or a portion of the supplemental 
11    procurement plan, accompanied by specific alternative 
12    wording or proposals. All comments shall be posted on the 
13    Agency's and Commission's websites. Within 14 days 
14    following the end of the 14-day review period, the Agency 
15    shall revise the supplemental procurement plan as 
16    necessary based on the comments received and file its 
17    revised supplemental procurement plan with the Commission 
18    for approval.
19        (2) Within 5 days after the filing of the supplemental 
20    procurement plan at the Commission, any person objecting 
21    to the supplemental procurement plan shall file an 
22    objection with the Commission. Within 10 days after the 
23    filing, the Commission shall determine whether a hearing 
24    is necessary. The Commission shall enter its order 
25    confirming or modifying the supplemental procurement plan 
26    within 90 days after the filing of the supplemental 
 
 
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1    procurement plan by the Agency.
2        (3) The Commission shall approve the supplemental 
3    procurement plan of renewable energy credits to be 
4    procured from new or existing photovoltaics, including, 
5    but not limited to, distributed photovoltaic generation, 
6    if the Commission determines that it will ensure adequate, 
7    reliable, affordable, efficient, and environmentally 
8    sustainable electric service in the form of renewable 
9    energy credits at the lowest total cost over time, taking 
10    into account any benefits of price stability.
11        (4) The supplemental procurement process under this 
12    subsection (i) shall include each of the following 
13    components:
14            (A) Procurement administrator. The Agency may 
15        retain a procurement administrator in the manner set 
16        forth in item (2) of subsection (a) of Section 1-75 of 
17        this Act to conduct the supplemental procurement or 
18        may elect to use the same procurement administrator 
19        administering the Agency's annual procurement under 
20        Section 1-75.
21            (B) Procurement monitor. The procurement monitor 
22        retained by the Commission pursuant to Section 
23        16-111.5 of the Public Utilities Act shall:
24                (i) monitor interactions among the procurement 
25            administrator and bidders and suppliers;
26                (ii) monitor and report to the Commission on 
 
 
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1            the progress of the supplemental procurement 
2            process;
3                (iii) provide an independent confidential 
4            report to the Commission regarding the results of 
5            the procurement events;
6                (iv) assess compliance with the procurement 
7            plan approved by the Commission for the 
8            supplemental procurement process;
9                (v) preserve the confidentiality of supplier 
10            and bidding information in a manner consistent 
11            with all applicable laws, rules, regulations, and 
12            tariffs;
13                (vi) provide expert advice to the Commission 
14            and consult with the procurement administrator 
15            regarding issues related to procurement process 
16            design, rules, protocols, and policy-related 
17            matters;
18                (vii) consult with the procurement 
19            administrator regarding the development and use of 
20            benchmark criteria, standard form contracts, 
21            credit policies, and bid documents; and
22                (viii) perform, with respect to the 
23            supplemental procurement process, any other 
24            procurement monitor duties specifically delineated 
25            within subsection (i) of this Section. 
26            (C) Solicitation, prequalification, and 
 
 
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1        registration of bidders. The procurement administrator 
2        shall disseminate information to potential bidders to 
3        promote a procurement event, notify potential bidders 
4        that the procurement administrator may enter into a 
5        post-bid price negotiation with bidders that meet the 
6        applicable benchmarks, provide supply requirements, 
7        and otherwise explain the competitive procurement 
8        process. In addition to such other publication as the 
9        procurement administrator determines is appropriate, 
10        this information shall be posted on the Agency's and 
11        the Commission's websites. The procurement 
12        administrator shall also administer the 
13        prequalification process, including evaluation of 
14        credit worthiness, compliance with procurement rules, 
15        and agreement to the standard form contract developed 
16        pursuant to item (D) of this paragraph (4). The 
17        procurement administrator shall then identify and 
18        register bidders to participate in the procurement 
19        event.
20            (D) Standard contract forms and credit terms and 
21        instruments. The procurement administrator, in 
22        consultation with the Agency, the Commission, and 
23        other interested parties and subject to Commission 
24        oversight, shall develop and provide standard contract 
25        forms for the supplier contracts that meet generally 
26        accepted industry practices as well as include any 
 
 
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1        applicable State of Illinois terms and conditions that 
2        are required for contracts entered into by an agency 
3        of the State of Illinois. Standard credit terms and 
4        instruments that meet generally accepted industry 
5        practices shall be similarly developed. Contracts for 
6        new photovoltaics shall include a provision attesting 
7        that the supplier will use a qualified person for the 
8        installation of the device pursuant to paragraph (1) 
9        of subsection (i) of this Section. The procurement 
10        administrator shall make available to the Commission 
11        all written comments it receives on the contract 
12        forms, credit terms, or instruments. If the 
13        procurement administrator cannot reach agreement with 
14        the parties as to the contract terms and conditions, 
15        the procurement administrator must notify the 
16        Commission of any disputed terms and the Commission 
17        shall resolve the dispute. The terms of the contracts 
18        shall not be subject to negotiation by winning 
19        bidders, and the bidders must agree to the terms of the 
20        contract in advance so that winning bids are selected 
21        solely on the basis of price.
22            (E) Requests for proposals; competitive 
23        procurement process. The procurement administrator 
24        shall design and issue requests for proposals to 
25        supply renewable energy credits in accordance with the 
26        supplemental procurement plan, as approved by the 
 
 
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1        Commission. The requests for proposals shall set forth 
2        a procedure for sealed, binding commitment bidding 
3        with pay-as-bid settlement, and provision for 
4        selection of bids on the basis of price, provided, 
5        however, that no bid shall be accepted if it exceeds 
6        the benchmark developed pursuant to item (F) of this 
7        paragraph (4).
8            (F) Benchmarks. Benchmarks for each product to be 
9        procured shall be developed by the procurement 
10        administrator in consultation with Commission staff, 
11        the Agency, and the procurement monitor for use in 
12        this supplemental procurement.
13            (G) A plan for implementing contingencies in the 
14        event of supplier default, Commission rejection of 
15        results, or any other cause.
16        (5) Within 2 business days after opening the sealed 
17    bids, the procurement administrator shall submit a 
18    confidential report to the Commission. The report shall 
19    contain the results of the bidding for each of the 
20    products along with the procurement administrator's 
21    recommendation for the acceptance and rejection of bids 
22    based on the price benchmark criteria and other factors 
23    observed in the process. The procurement monitor also 
24    shall submit a confidential report to the Commission 
25    within 2 business days after opening the sealed bids. The 
26    report shall contain the procurement monitor's assessment 
 
 
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1    of bidder behavior in the process as well as an assessment 
2    of the procurement administrator's compliance with the 
3    procurement process and rules. The Commission shall review 
4    the confidential reports submitted by the procurement 
5    administrator and procurement monitor and shall accept or 
6    reject the recommendations of the procurement 
7    administrator within 2 business days after receipt of the 
8    reports.
9        (6) Within 3 business days after the Commission 
10    decision approving the results of a procurement event, the 
11    Agency shall enter into binding contractual arrangements 
12    with the winning suppliers using the standard form 
13    contracts.
14        (7) The names of the successful bidders and the 
15    average of the winning bid prices for each contract type 
16    and for each contract term shall be made available to the 
17    public within 2 days after the supplemental procurement 
18    event. The Commission, the procurement monitor, the 
19    procurement administrator, the Agency, and all 
20    participants in the procurement process shall maintain the 
21    confidentiality of all other supplier and bidding 
22    information in a manner consistent with all applicable 
23    laws, rules, regulations, and tariffs. Confidential 
24    information, including the confidential reports submitted 
25    by the procurement administrator and procurement monitor 
26    pursuant to this Section, shall not be made publicly 
 
 
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1    available and shall not be discoverable by any party in 
2    any proceeding, absent a compelling demonstration of need, 
3    nor shall those reports be admissible in any proceeding 
4    other than one for law enforcement purposes.
5        (8) The supplemental procurement provided in this 
6    subsection (i) shall not be subject to the requirements 
7    and limitations of subsections (c) and (d) of this 
8    Section.
9        (9) Expenses incurred in connection with the 
10    procurement process held pursuant to this Section, 
11    including, but not limited to, the cost of developing the 
12    supplemental procurement plan, the procurement 
13    administrator, procurement monitor, and the cost of the 
14    retirement of renewable energy credits purchased pursuant 
15    to the supplemental procurement shall be paid for from the 
16    Illinois Power Agency Renewable Energy Resources Fund. The 
17    Agency shall enter into an interagency agreement with the 
18    Commission to reimburse the Commission for its costs 
19    associated with the procurement monitor for the 
20    supplemental procurement process. 
21(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23; 
22103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; revised 
236-23-25.)
 
24    (20 ILCS 3855/1-75)
25    Sec. 1-75. Planning and Procurement Bureau. The Planning 
 
 
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1and Procurement Bureau has the following duties and 
2responsibilities:
3    (a) The Planning and Procurement Bureau shall each year, 
4beginning in 2008, develop procurement plans and conduct 
5competitive procurement processes in accordance with the 
6requirements of Section 16-111.5 of the Public Utilities Act 
7for the eligible retail customers of electric utilities that 
8on December 31, 2005 provided electric service to at least 
9100,000 customers in Illinois. Beginning with the delivery 
10year commencing on June 1, 2017, the Planning and Procurement 
11Bureau shall develop plans and processes for the procurement 
12of zero emission credits from zero emission facilities in 
13accordance with the requirements of subsection (d-5) of this 
14Section. Beginning on the effective date of this amendatory 
15Act of the 102nd General Assembly, the Planning and 
16Procurement Bureau shall develop plans and processes for the 
17procurement of carbon mitigation credits from carbon-free 
18energy resources in accordance with the requirements of 
19subsection (d-10) of this Section. The Planning and 
20Procurement Bureau shall also develop procurement plans and 
21conduct competitive procurement processes in accordance with 
22the requirements of Section 16-111.5 of the Public Utilities 
23Act for the eligible retail customers of small 
24multi-jurisdictional electric utilities that (i) on December 
2531, 2005 served less than 100,000 customers in Illinois and 
26(ii) request a procurement plan for their Illinois 
 
 
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1jurisdictional load. This Section shall not apply to a small 
2multi-jurisdictional utility until such time as a small 
3multi-jurisdictional utility requests the Agency to prepare a 
4procurement plan for their Illinois jurisdictional load. For 
5the purposes of this Section, the term "eligible retail 
6customers" has the same definition as found in Section 
716-111.5(a) of the Public Utilities Act.
8    Beginning with the plan or plans to be implemented in the 
92017 delivery year, the Agency shall no longer include the 
10procurement of renewable energy resources in the annual 
11procurement plans required by this subsection (a), except as 
12provided in subsection (q) of Section 16-111.5 of the Public 
13Utilities Act, and shall instead develop a long-term renewable 
14resources procurement plan in accordance with subsection (c) 
15of this Section and Section 16-111.5 of the Public Utilities 
16Act. 
17    In accordance with subsection (c-5) of this Section, the 
18Planning and Procurement Bureau shall oversee the procurement 
19by electric utilities that served more than 300,000 retail 
20customers in this State as of January 1, 2019 of renewable 
21energy credits from new utility-scale solar projects to be 
22installed, along with energy storage facilities, at or 
23adjacent to the sites of electric generating facilities that, 
24as of January 1, 2016, burned coal as their primary fuel 
25source. 
26        (1) The Agency shall each year, beginning in 2008, as 
 
 
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1    needed, issue a request for qualifications for experts or 
2    expert consulting firms to develop the procurement plans 
3    in accordance with Section 16-111.5 of the Public 
4    Utilities Act. In order to qualify an expert or expert 
5    consulting firm must have:
6            (A) direct previous experience assembling 
7        large-scale power supply plans or portfolios for 
8        end-use customers;
9            (B) an advanced degree in economics, mathematics, 
10        engineering, risk management, or a related area of 
11        study;
12            (C) 10 years of experience in the electricity 
13        sector, including managing supply risk;
14            (D) expertise in wholesale electricity market 
15        rules, including those established by the Federal 
16        Energy Regulatory Commission and regional transmission 
17        organizations;
18            (E) expertise in credit protocols and familiarity 
19        with contract protocols;
20            (F) adequate resources to perform and fulfill the 
21        required functions and responsibilities; and
22            (G) the absence of a conflict of interest and 
23        inappropriate bias for or against potential bidders or 
24        the affected electric utilities.
25        (2) The Agency shall each year, as needed, issue a 
26    request for qualifications for a procurement administrator 
 
 
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1    to conduct the competitive procurement processes in 
2    accordance with Section 16-111.5 of the Public Utilities 
3    Act. In order to qualify an expert or expert consulting 
4    firm must have:
5            (A) direct previous experience administering a 
6        large-scale competitive procurement process;
7            (B) an advanced degree in economics, mathematics, 
8        engineering, or a related area of study;
9            (C) 10 years of experience in the electricity 
10        sector, including risk management experience;
11            (D) expertise in wholesale electricity market 
12        rules, including those established by the Federal 
13        Energy Regulatory Commission and regional transmission 
14        organizations; 
15            (E) expertise in credit and contract protocols;
16            (F) adequate resources to perform and fulfill the 
17        required functions and responsibilities; and
18            (G) the absence of a conflict of interest and 
19        inappropriate bias for or against potential bidders or 
20        the affected electric utilities.
21        (3) The Agency shall provide affected utilities and 
22    other interested parties with the lists of qualified 
23    experts or expert consulting firms identified through the 
24    request for qualifications processes that are under 
25    consideration to develop the procurement plans and to 
26    serve as the procurement administrator. The Agency shall 
 
 
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1    also provide each qualified expert's or expert consulting 
2    firm's response to the request for qualifications. All 
3    information provided under this subparagraph shall also be 
4    provided to the Commission. The Agency may provide by rule 
5    for fees associated with supplying the information to 
6    utilities and other interested parties. These parties 
7    shall, within 5 business days, notify the Agency in 
8    writing if they object to any experts or expert consulting 
9    firms on the lists. Objections shall be based on:
10            (A) failure to satisfy qualification criteria;
11            (B) identification of a conflict of interest; or
12            (C) evidence of inappropriate bias for or against 
13        potential bidders or the affected utilities.
14        The Agency shall remove experts or expert consulting 
15    firms from the lists within 10 days if there is a 
16    reasonable basis for an objection and provide the updated 
17    lists to the affected utilities and other interested 
18    parties. If the Agency fails to remove an expert or expert 
19    consulting firm from a list, an objecting party may seek 
20    review by the Commission within 5 days thereafter by 
21    filing a petition, and the Commission shall render a 
22    ruling on the petition within 10 days. There is no right of 
23    appeal of the Commission's ruling.
24        (4) The Agency shall issue requests for proposals to 
25    the qualified experts or expert consulting firms to 
26    develop a procurement plan for the affected utilities and 
 
 
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1    to serve as procurement administrator.
2        (5) The Agency shall select an expert or expert 
3    consulting firm to develop procurement plans based on the 
4    proposals submitted and shall award contracts of up to 5 
5    years to those selected.
6        (6) The Agency shall select an expert or expert 
7    consulting firm, with approval of the Commission, to serve 
8    as procurement administrator based on the proposals 
9    submitted. If the Commission rejects, within 5 days, the 
10    Agency's selection, the Agency shall submit another 
11    recommendation within 3 days based on the proposals 
12    submitted. The Agency shall award a 5-year contract to the 
13    expert or expert consulting firm so selected with 
14    Commission approval.
15    (b) The experts or expert consulting firms retained by the 
16Agency shall, as appropriate, prepare procurement plans, and 
17conduct a competitive procurement process as prescribed in 
18Section 16-111.5 of the Public Utilities Act, to ensure 
19adequate, reliable, affordable, efficient, and environmentally 
20sustainable electric service at the lowest total cost over 
21time, taking into account any benefits of price stability, for 
22eligible retail customers of electric utilities that on 
23December 31, 2005 provided electric service to at least 
24100,000 customers in the State of Illinois, and for eligible 
25Illinois retail customers of small multi-jurisdictional 
26electric utilities that (i) on December 31, 2005 served less 
 
 
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1than 100,000 customers in Illinois and (ii) request a 
2procurement plan for their Illinois jurisdictional load.
3    (c) Renewable portfolio standard.
4        (1)(A) The Agency shall develop a long-term renewable 
5    resources procurement plan that shall include procurement 
6    programs and competitive procurement events necessary to 
7    meet the goals set forth in this subsection (c). The 
8    initial long-term renewable resources procurement plan 
9    shall be released for comment no later than 160 days after 
10    June 1, 2017 (the effective date of Public Act 99-906). 
11    The Agency shall review, and may revise on an expedited 
12    basis, the long-term renewable resources procurement plan 
13    at least every 2 years, which shall be conducted in 
14    conjunction with the procurement plan under Section 
15    16-111.5 of the Public Utilities Act to the extent 
16    practicable to minimize administrative expense. No later 
17    than 120 days after the effective date of this amendatory 
18    Act of the 103rd General Assembly, the Agency shall 
19    release for comment a revision to the long-term renewable 
20    resources procurement plan, updating elements of the most 
21    recently approved plan as needed to comply with this 
22    amendatory Act of the 103rd General Assembly, and any 
23    long-term renewable resources procurement plan update 
24    published by the Agency but not yet approved by the 
25    Illinois Commerce Commission shall be withdrawn. The 
26    long-term renewable resources procurement plans shall be 
 
 
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1    subject to review and approval by the Commission under 
2    Section 16-111.5 of the Public Utilities Act.
3        (B) Subject to subparagraph (F) of this paragraph (1), 
4    the long-term renewable resources procurement plan shall 
5    attempt to meet the goals for procurement of renewable 
6    energy credits at levels of at least the following overall 
7    percentages: 13% by the 2017 delivery year; increasing by 
8    at least 1.5% each delivery year thereafter to at least 
9    25% by the 2025 delivery year; increasing by at least 3% 
10    each delivery year thereafter to at least 40% by the 2030 
11    delivery year, and continuing at no less than 40% for each 
12    delivery year thereafter. The Agency shall attempt to 
13    procure 50% by delivery year 2040. The Agency shall 
14    determine the annual increase between delivery year 2030 
15    and delivery year 2040, if any, taking into account energy 
16    demand, other energy resources, and other public policy 
17    goals. In the event of a conflict between these goals and 
18    the new wind, new photovoltaic, and hydropower procurement 
19    requirements described in items (i) through (iii) of 
20    subparagraph (C) of this paragraph (1), the long-term plan 
21    shall prioritize compliance with the new wind, new 
22    photovoltaic, and hydropower procurement requirements 
23    described in items (i) through (iii) of subparagraph (C) 
24    of this paragraph (1) over the annual percentage targets 
25    described in this subparagraph (B). The Agency shall not 
26    comply with the annual percentage targets described in 
 
 
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1    this subparagraph (B) by procuring renewable energy 
2    credits that are unlikely to lead to the development of 
3    new renewable resources or new, modernized, or retooled 
4    hydropower facilities. 
5        For the delivery year beginning June 1, 2017, the 
6    procurement plan shall attempt to include, subject to the 
7    prioritization outlined in this subparagraph (B), 
8    cost-effective renewable energy resources equal to at 
9    least 13% of each utility's load for eligible retail 
10    customers and 13% of the applicable portion of each 
11    utility's load for retail customers who are not eligible 
12    retail customers, which applicable portion shall equal 50% 
13    of the utility's load for retail customers who are not 
14    eligible retail customers on February 28, 2017. 
15        For the delivery year beginning June 1, 2018, the 
16    procurement plan shall attempt to include, subject to the 
17    prioritization outlined in this subparagraph (B), 
18    cost-effective renewable energy resources equal to at 
19    least 14.5% of each utility's load for eligible retail 
20    customers and 14.5% of the applicable portion of each 
21    utility's load for retail customers who are not eligible 
22    retail customers, which applicable portion shall equal 75% 
23    of the utility's load for retail customers who are not 
24    eligible retail customers on February 28, 2017. 
25        For the delivery year beginning June 1, 2019, and for 
26    each year thereafter, the procurement plans shall attempt 
 
 
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1    to include, subject to the prioritization outlined in this 
2    subparagraph (B), cost-effective renewable energy 
3    resources equal to a minimum percentage of each utility's 
4    load for all retail customers as follows: 16% by June 1, 
5    2019; increasing by 1.5% each year thereafter to 25% by 
6    June 1, 2025; and 25% by June 1, 2026; increasing by at 
7    least 3% each delivery year thereafter to at least 40% by 
8    the 2030 delivery year, and continuing at no less than 40% 
9    for each delivery year thereafter. The Agency shall 
10    attempt to procure 50% by delivery year 2040. The Agency 
11    shall determine the annual increase between delivery year 
12    2030 and delivery year 2040, if any, taking into account 
13    energy demand, other energy resources, and other public 
14    policy goals. 
15        For each delivery year, the Agency shall first 
16    recognize each utility's obligations for that delivery 
17    year under existing contracts. Any renewable energy 
18    credits under existing contracts, including renewable 
19    energy credits as part of renewable energy resources, 
20    shall be used to meet the goals set forth in this 
21    subsection (c) for the delivery year. 
22        (C) The long-term renewable resources procurement plan 
23    described in subparagraph (A) of this paragraph (1) shall 
24    include the procurement of renewable energy credits from 
25    new projects pursuant to the following terms: 
26            (i) At least 10,000,000 renewable energy credits 
 
 
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1        delivered annually by the end of the 2021 delivery 
2        year, and increasing ratably to reach 45,000,000 
3        renewable energy credits delivered annually from new 
4        wind and solar projects, from repowered wind projects, 
5        or from retooled hydropower facilities by the end of 
6        delivery year 2030 such that the goals in subparagraph 
7        (B) of this paragraph (1) are met entirely by 
8        procurements of renewable energy credits from new wind 
9        and photovoltaic projects. Of that amount, to the 
10        extent possible, the Agency shall endeavor to procure 
11        45% from new and repowered wind and hydropower 
12        projects and shall procure at least 55% from 
13        photovoltaic projects. Of the amount to be procured 
14        from photovoltaic projects, the Agency shall procure: 
15        at least 50% from solar photovoltaic projects using 
16        the program outlined in subparagraph (K) of this 
17        paragraph (1) from distributed renewable energy 
18        generation devices or community renewable generation 
19        projects; at least 47% from utility-scale solar 
20        projects; at least 3% from brownfield site 
21        photovoltaic projects that are not community renewable 
22        generation projects. The Agency may propose 
23        adjustments to these percentages, including 
24        establishing percentage-based goals for the 
25        procurement of renewable energy credits from 
26        modernized or retooled hydropower facilities and 
 
 
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1        repowered wind projects, through its long-term 
2        renewable resources plan described in subparagraph (A) 
3        of this paragraph (1) as necessary based on developer 
4        interest, market conditions, budget considerations, 
5        resource adequacy needs, or other factors. 
6            In developing the long-term renewable resources 
7        procurement plan, the Agency shall consider other 
8        approaches, in addition to competitive procurements, 
9        that can be used to procure renewable energy credits 
10        from brownfield site photovoltaic projects and thereby 
11        help return blighted or contaminated land to 
12        productive use while enhancing public health and the 
13        well-being of Illinois residents, including those in 
14        environmental justice communities, as defined using 
15        existing methodologies and findings used by the Agency 
16        and its Administrator in its Illinois Solar for All 
17        Program. The Agency shall also consider other 
18        approaches, in addition to competitive procurements, 
19        to procure renewable energy credits from new and 
20        existing hydropower facilities to support the 
21        development and maintenance of these facilities. The 
22        Agency shall explore options to convert existing dams 
23        but shall not consider approaches to develop new dams 
24        where they do not already exist. To encourage the 
25        continued operation of utility-scale wind projects, 
26        the Agency shall consider and may propose other 
 
 
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1        approaches in addition to competitive procurements to 
2        procure renewable energy credits from repowered wind 
3        projects. 
4            (ii) In any given delivery year, if forecasted 
5        expenses are less than the maximum budget available 
6        under subparagraph (E) of this paragraph (1), the 
7        Agency shall continue to procure new renewable energy 
8        credits until that budget is exhausted in the manner 
9        outlined in item (i) of this subparagraph (C).
10            (iii) For purposes of this Section:
11            "New wind projects" means wind renewable energy 
12        facilities that are energized after June 1, 2017 for 
13        the delivery year commencing June 1, 2017.
14            "New photovoltaic projects" means photovoltaic 
15        renewable energy facilities that are energized after 
16        June 1, 2017. Photovoltaic projects developed under 
17        Section 1-56 of this Act shall not apply towards the 
18        new photovoltaic project requirements in this 
19        subparagraph (C). 
20            "Repowered wind projects" means utility-scale wind 
21        projects featuring the removal, replacement, or 
22        expansion of turbines at an existing project site, as 
23        defined in the long-term renewable resources 
24        procurement plan, after the effective date of this 
25        amendatory Act of the 103rd General Assembly. 
26        Renewable energy credit contract awards used to 
 
 
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1        support repowered wind projects shall only cover the 
2        incremental increase in facility electricity 
3        production resultant from repowering. 
4            For purposes of calculating whether the Agency has 
5        procured enough new wind and solar renewable energy 
6        credits required by this subparagraph (C), renewable 
7        energy facilities that have a multi-year renewable 
8        energy credit delivery contract with the utility 
9        through at least delivery year 2030 shall be 
10        considered new, however no renewable energy credits 
11        from contracts entered into before June 1, 2021 shall 
12        be used to calculate whether the Agency has procured 
13        the correct proportion of new wind and new solar 
14        contracts described in this subparagraph (C) for 
15        delivery year 2021 and thereafter.
16            (iv) The Agency may implement additional measures, 
17        including eligibility requirements, to ensure that new 
18        wind projects and new photovoltaic projects supported 
19        through renewable energy credit contract awards are a 
20        result of a contract award and are otherwise developed 
21        pursuant to the financial certainty provided through a 
22        contract award.
23        (D) Renewable energy credits shall be cost effective. 
24    For purposes of this subsection (c), "cost effective" 
25    means that the costs of procuring renewable energy 
26    resources do not cause the limit stated in subparagraph 
 
 
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1    (E) of this paragraph (1) to be exceeded and, for 
2    renewable energy credits procured through a competitive 
3    procurement event, do not exceed benchmarks based on 
4    market prices for like products in the region. For 
5    purposes of this subsection (c), "like products" means 
6    contracts for renewable energy credits from the same or 
7    substantially similar technology, same or substantially 
8    similar vintage (new or existing), the same or 
9    substantially similar quantity, and the same or 
10    substantially similar contract length and structure. 
11    Benchmarks shall reflect development, financing, or 
12    related costs resulting from requirements imposed through 
13    other provisions of State law, including, but not limited 
14    to, requirements in subparagraphs (P) and (Q) of this 
15    paragraph (1) and the Renewable Energy Facilities 
16    Agricultural Impact Mitigation Act. Confidential 
17    benchmarks shall be developed by the procurement 
18    administrator, in consultation with the Commission staff, 
19    Agency staff, and the procurement monitor and shall be 
20    subject to Commission review and approval. If price 
21    benchmarks for like products in the region are not 
22    available, the procurement administrator shall establish 
23    price benchmarks based on publicly available data on 
24    regional technology costs and expected current and future 
25    regional energy prices. The benchmarks in this Section 
26    shall not be used to curtail or otherwise reduce 
 
 
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1    contractual obligations entered into by or through the 
2    Agency prior to June 1, 2017 (the effective date of Public 
3    Act 99-906). 
4        (E) For purposes of this subsection (c), the required 
5    procurement of cost-effective renewable energy resources 
6    for a particular year commencing prior to June 1, 2017 
7    shall be measured as a percentage of the actual amount of 
8    electricity (megawatt-hours) supplied by the electric 
9    utility to eligible retail customers in the delivery year 
10    ending immediately prior to the procurement, and, for 
11    delivery years commencing on and after June 1, 2017, the 
12    required procurement of cost-effective renewable energy 
13    resources for a particular year shall be measured as a 
14    percentage of the actual amount of electricity 
15    (megawatt-hours) delivered by the electric utility in the 
16    delivery year ending immediately prior to the procurement, 
17    to all retail customers in its service territory. For 
18    purposes of this subsection (c), the amount paid per 
19    kilowatthour means the total amount paid for electric 
20    service expressed on a per kilowatthour basis. For 
21    purposes of this subsection (c), the total amount paid for 
22    electric service includes without limitation amounts paid 
23    for supply, transmission, capacity, distribution, 
24    surcharges, and add-on taxes. 
25        Notwithstanding the requirements of this subsection 
26    (c), and except as provided in subparagraph (E-5) of 
 
 
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1    paragraph (1) of this subsection (c) or except as 
2    otherwise authorized by the Commission in its approval of 
3    the integrated resource plan under Section 16-202 of the 
4    Public Utilities Act, the total of renewable energy 
5    resources procured under the procurement plan for any 
6    single year shall be subject to the limitations of this 
7    subparagraph (E). Such procurement shall be reduced for 
8    all retail customers based on the amount necessary to 
9    limit the annual estimated average net increase due to the 
10    costs of these resources included in the amounts paid by 
11    eligible retail customers in connection with electric 
12    service to no more than 4.25% of the amount paid per 
13    kilowatthour by those customers during the year ending May 
14    31, 2009, adjusted annually for inflation starting with 
15    the first adjustment in the delivery year commencing June 
16    1, 2026. For the purposes of this Section, the inflation 
17    adjustment shall not be accrued or applied retroactively 
18    prior to the effective date of this amendatory Act of the 
19    104th General Assembly and shall apply prospectively 
20    starting in 2025. The limitation shall be increased by an 
21    additional 1.65 percentage points of the amount paid per 
22    kilowatthour by eligible retail customers during the year 
23    ending May 31, 2009 starting with the delivery year 
24    commencing June 1, 2027. To arrive at a maximum dollar 
25    amount of renewable energy resources to be procured for 
26    the particular delivery year, the resulting per 
 
 
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1    kilowatthour amount shall be applied to the actual amount 
2    of kilowatthours of electricity delivered, or applicable 
3    portion of such amount as specified in paragraph (1) of 
4    this subsection (c), as applicable, by the electric 
5    utility in the delivery year immediately prior to the 
6    procurement to all retail customers in its service 
7    territory. The calculations required by this subparagraph 
8    (E) shall be made only once for each delivery year at the 
9    time that the renewable energy resources are procured. 
10    Once the determination as to the amount of renewable 
11    energy resources to procure is made based on the 
12    calculations set forth in this subparagraph (E) and the 
13    contracts procuring those amounts are executed between the 
14    seller and applicable electric utility, no subsequent rate 
15    impact determinations shall be made and no adjustments to 
16    those contract amounts shall be allowed. As provided in 
17    subparagraph (E-5) of paragraph (1) of this subsection 
18    (c), the seller shall be entitled to full, prompt, and 
19    uninterrupted payment under the applicable contract 
20    notwithstanding the application of this subparagraph (E), 
21    and all costs incurred under such contracts shall be fully 
22    recoverable by the electric utility as provided in this 
23    Section. 
24        (E-5) If, for a particular delivery year, the 
25    limitation on the amount of renewable energy resources to 
26    be procured, as calculated pursuant to subparagraph (E) of 
 
 
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1    paragraph (1) of this subsection (c), would result in an 
2    insufficient collection of funds to fully pay amounts due 
3    to a seller under existing contracts executed under this 
4    Section or executed under Section 1-56 of this Act, then 
5    the following provisions shall apply to ensure full and 
6    uninterrupted payment is made to such seller or sellers:
7            (i) If the electric utility has retained unspent 
8        funds in an interest-bearing account as prescribed in 
9        subsection (k) of Section 16-108 of the Public 
10        Utilities Act, then the utility shall use those funds 
11        to remit full payment to the sellers to ensure prompt 
12        and uninterrupted payment of existing contractual 
13        obligation.
14            (ii) If the funds described in item (i) of this 
15        subparagraph (E-5) are insufficient to satisfy all 
16        existing contractual obligations, then the electric 
17        utility shall, nonetheless, remit full payment to the 
18        sellers to ensure prompt and uninterrupted payment of 
19        existing contractual obligations, provided that the 
20        full costs shall be recoverable by the utility in 
21        accordance with part (ee) of item (iv) of this 
22        subsection (E-5).
23            (iii) The Agency shall promptly notify the 
24        Commission that existing contractual obligations are 
25        reasonably expected to exceed the maximum collection 
26        authorized under subparagraph (E) of paragraph (1) of 
 
 
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1        this subsection (c) for the applicable delivery year. 
2        The Agency shall also explain and confirm how the 
3        operation of items (i) and (ii) of this subparagraph 
4        (E-5) ensures that the electric utility will continue 
5        to make prompt and uninterrupted payment under 
6        existing contractual obligations. The Agency shall 
7        provide this information to the Commission through a 
8        notice filed in the Commission docket approving the 
9        Agency's operative Long-Term Renewable Resources 
10        Procurement Plan that includes the applicable delivery 
11        year.
12            (iv) The Agency shall suspend or reduce new 
13        contract awards for the procurement of renewable 
14        energy credits until an Agency determination is made 
15        under subparagraph (E) that additional procurements 
16        would not cause the rate impact limitation of 
17        subparagraph (E) to be exceeded. At least once 
18        annually after the notice provided for in item (iii) 
19        of this subparagraph (E-5) is made, the Agency shall 
20        analyze existing contract obligations, projected 
21        prices for indexed renewable energy credit contracts 
22        executed under item (v) of subparagraph (G) of 
23        paragraph (1) of subsection (c) of Section 1-75 of 
24        this Act, and expected collections authorized under 
25        subparagraph (E) to determine whether and to what 
26        extent the limitations of subparagraph (E) would be 
 
 
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1        exceeded by additional renewable energy credit 
2        procurement contract awards.
3                (aa) If the Agency determines that additional 
4            renewable energy credit procurement contract 
5            awards could be made without exceeding the 
6            limitations of subparagraph (E), then the 
7            procurements shall be authorized at a scale 
8            determined not to exceed the limitations of 
9            subparagraph (E) in a manner consistent with the 
10            priorities of this Section.
11                (bb) If the Agency determines that additional 
12            renewable energy credit procurement contract 
13            awards cannot be made without exceeding the 
14            limitations of subparagraph (E), then the Agency 
15            shall suspend any new contract awards for the 
16            procurement of renewable energy credits until a 
17            new rate impact determination is made under 
18            subparagraph (E).
19                (cc) Agency determinations made under this 
20            item (iv) shall be detailed and comprehensive and, 
21            if not made through the Agency's Long-Term 
22            Renewable Resources Procurement Plan, shall be 
23            filed as a compliance filing in the most recent 
24            docketed proceeding approving the Agency's 
25            Long-Term Renewable Resources Procurement Plan.
26                (dd) With respect to the procurement of 
 
 
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1            renewable energy credits authorized through 
2            programs administered under subsection (b) of 
3            Section 1-56 and subparagraphs (K) through (M) of 
4            paragraph (1) of subsection (k) of Section 1-75 of 
5            this Act, the award of contracts for the 
6            procurement of renewable energy credits shall be 
7            suspended or reduced only at the conclusion of the 
8            program year in which the notice provided for 
9            under item (iii) of this subparagraph (E-5) is 
10            made. 
11                (ee) The contract shall provide that, so long 
12            as at least one of: (i) the cost recovery 
13            mechanisms referenced in subsection (k) of Section 
14            16-108 and subsection (l) of Section 16-111.5 of 
15            the Public Utilities Act remains in full force 
16            without limitation or (ii) the utility is 
17            otherwise authorized and or entitled to full, 
18            prompt, and uninterrupted recovery of its costs 
19            through any other mechanism, then such seller 
20            shall be entitled to full, prompt, and 
21            uninterrupted payment under the applicable 
22            contract notwithstanding the application of this 
23            subparagraph (E). 
24        (F) If the limitation on the amount of renewable 
25    energy resources procured in subparagraph (E) of this 
26    paragraph (1) prevents the Agency from meeting all of the 
 
 
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1    goals in this subsection (c), the Agency's long-term plan 
2    shall prioritize compliance with the requirements of this 
3    subsection (c) regarding renewable energy credits in the 
4    following order:
5            (i) renewable energy credits under existing 
6        contractual obligations as of June 1, 2021;
7            (i-5) funding for the Illinois Solar for All 
8        Program, as described in subparagraph (O) of this 
9        paragraph (1); 
10            (ii) renewable energy credits necessary to comply 
11        with the new wind and new photovoltaic procurement 
12        requirements described in items (i) through (iii) of 
13        subparagraph (C) of this paragraph (1); and
14            (iii) renewable energy credits necessary to meet 
15        the remaining requirements of this subsection (c).
16        (G) The following provisions shall apply to the 
17    Agency's procurement of renewable energy credits under 
18    this subsection (c):
19            (i) Notwithstanding whether a long-term renewable 
20        resources procurement plan has been approved, the 
21        Agency shall conduct an initial forward procurement 
22        for renewable energy credits from new utility-scale 
23        wind projects within 160 days after June 1, 2017 (the 
24        effective date of Public Act 99-906). For the purposes 
25        of this initial forward procurement, the Agency shall 
26        solicit 15-year contracts for delivery of 1,000,000 
 
 
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1        renewable energy credits delivered annually from new 
2        utility-scale wind projects to begin delivery on June 
3        1, 2019, if available, but not later than June 1, 2021, 
4        unless the project has delays in the establishment of 
5        an operating interconnection with the applicable 
6        transmission or distribution system as a result of the 
7        actions or inactions of the transmission or 
8        distribution provider, or other causes for force 
9        majeure as outlined in the procurement contract, in 
10        which case, not later than June 1, 2022. Payments to 
11        suppliers of renewable energy credits shall commence 
12        upon delivery. Renewable energy credits procured under 
13        this initial procurement shall be included in the 
14        Agency's long-term plan and shall apply to all 
15        renewable energy goals in this subsection (c).
16            (ii) Notwithstanding whether a long-term renewable 
17        resources procurement plan has been approved, the 
18        Agency shall conduct an initial forward procurement 
19        for renewable energy credits from new utility-scale 
20        solar projects and brownfield site photovoltaic 
21        projects within one year after June 1, 2017 (the 
22        effective date of Public Act 99-906). For the purposes 
23        of this initial forward procurement, the Agency shall 
24        solicit 15-year contracts for delivery of 1,000,000 
25        renewable energy credits delivered annually from new 
26        utility-scale solar projects and brownfield site 
 
 
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1        photovoltaic projects to begin delivery on June 1, 
2        2019, if available, but not later than June 1, 2021, 
3        unless the project has delays in the establishment of 
4        an operating interconnection with the applicable 
5        transmission or distribution system as a result of the 
6        actions or inactions of the transmission or 
7        distribution provider, or other causes for force 
8        majeure as outlined in the procurement contract, in 
9        which case, not later than June 1, 2022. The Agency may 
10        structure this initial procurement in one or more 
11        discrete procurement events. Payments to suppliers of 
12        renewable energy credits shall commence upon delivery. 
13        Renewable energy credits procured under this initial 
14        procurement shall be included in the Agency's 
15        long-term plan and shall apply to all renewable energy 
16        goals in this subsection (c).
17            (iii) Notwithstanding whether the Commission has 
18        approved the periodic long-term renewable resources 
19        procurement plan revision described in Section 
20        16-111.5 of the Public Utilities Act, the Agency shall 
21        conduct at least one subsequent forward procurement 
22        for renewable energy credits from new utility-scale 
23        wind projects, new utility-scale solar projects, and 
24        new brownfield site photovoltaic projects within 240 
25        days after the effective date of this amendatory Act 
26        of the 102nd General Assembly in quantities necessary 
 
 
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1        to meet the requirements of subparagraph (C) of this 
2        paragraph (1) through the delivery year beginning June 
3        1, 2021.
4            (iv) Notwithstanding whether the Commission has 
5        approved the periodic long-term renewable resources 
6        procurement plan revision described in Section 
7        16-111.5 of the Public Utilities Act, the Agency shall 
8        open capacity for each category in the Adjustable 
9        Block program within 90 days after the effective date 
10        of this amendatory Act of the 102nd General Assembly 
11        manner:
12                (1) The Agency shall open the first block of 
13            annual capacity for the category described in item 
14            (i) of subparagraph (K) of this paragraph (1). The 
15            first block of annual capacity for item (i) shall 
16            be for at least 75 megawatts of total nameplate 
17            capacity. The price of the renewable energy credit 
18            for this block of capacity shall be 4% less than 
19            the price of the last open block in this category. 
20            Projects on a waitlist shall be awarded contracts 
21            first in the order in which they appear on the 
22            waitlist. Notwithstanding anything to the 
23            contrary, for those renewable energy credits that 
24            qualify and are procured under this subitem (1) of 
25            this item (iv), the renewable energy credit 
26            delivery contract value shall be paid in full, 
 
 
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1            based on the estimated generation during the first 
2            15 years of operation, by the contracting 
3            utilities at the time that the facility producing 
4            the renewable energy credits is interconnected at 
5            the distribution system level of the utility and 
6            verified as energized and in compliance by the 
7            Program Administrator. The electric utility shall 
8            receive and retire all renewable energy credits 
9            generated by the project for the first 15 years of 
10            operation. Renewable energy credits generated by 
11            the project thereafter shall not be transferred 
12            under the renewable energy credit delivery 
13            contract with the counterparty electric utility.
14                (2) The Agency shall open the first block of 
15            annual capacity for the category described in item 
16            (ii) of subparagraph (K) of this paragraph (1). 
17            The first block of annual capacity for item (ii) 
18            shall be for at least 75 megawatts of total 
19            nameplate capacity.
20                    (A) The price of the renewable energy 
21                credit for any project on a waitlist for this 
22                category before the opening of this block 
23                shall be 4% less than the price of the last 
24                open block in this category. Projects on the 
25                waitlist shall be awarded contracts first in 
26                the order in which they appear on the 
 
 
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1                waitlist. Any projects that are less than or 
2                equal to 25 kilowatts in size on the waitlist 
3                for this capacity shall be moved to the 
4                waitlist for paragraph (1) of this item (iv). 
5                Notwithstanding anything to the contrary, 
6                projects that were on the waitlist prior to 
7                opening of this block shall not be required to 
8                be in compliance with the requirements of 
9                subparagraph (Q) of this paragraph (1) of this 
10                subsection (c). Notwithstanding anything to 
11                the contrary, for those renewable energy 
12                credits procured from projects that were on 
13                the waitlist for this category before the 
14                opening of this block 20% of the renewable 
15                energy credit delivery contract value, based 
16                on the estimated generation during the first 
17                15 years of operation, shall be paid by the 
18                contracting utilities at the time that the 
19                facility producing the renewable energy 
20                credits is interconnected at the distribution 
21                system level of the utility and verified as 
22                energized by the Program Administrator. The 
23                remaining portion shall be paid ratably over 
24                the subsequent 4-year period. The electric 
25                utility shall receive and retire all renewable 
26                energy credits generated by the project during 
 
 
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1                the first 15 years of operation. Renewable 
2                energy credits generated by the project 
3                thereafter shall not be transferred under the 
4                renewable energy credit delivery contract with 
5                the counterparty electric utility.
6                    (B) The price of renewable energy credits 
7                for any project not on the waitlist for this 
8                category before the opening of the block shall 
9                be determined and published by the Agency. 
10                Projects not on a waitlist as of the opening 
11                of this block shall be subject to the 
12                requirements of subparagraph (Q) of this 
13                paragraph (1), as applicable. Projects not on 
14                a waitlist as of the opening of this block 
15                shall be subject to the contract provisions 
16                outlined in item (iii) of subparagraph (L) of 
17                this paragraph (1). The Agency shall strive to 
18                publish updated prices and an updated 
19                renewable energy credit delivery contract as 
20                quickly as possible. 
21                (3) For opening the first 2 blocks of annual 
22            capacity for projects participating in item (iii) 
23            of subparagraph (K) of paragraph (1) of subsection 
24            (c), projects shall be selected exclusively from 
25            those projects on the ordinal waitlists of 
26            community renewable generation projects 
 
 
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1            established by the Agency based on the status of 
2            those ordinal waitlists as of December 31, 2020, 
3            and only those projects previously determined to 
4            be eligible for the Agency's April 2019 community 
5            solar project selection process.
6                The first 2 blocks of annual capacity for item 
7            (iii) shall be for 250 megawatts of total 
8            nameplate capacity, with both blocks opening 
9            simultaneously under the schedule outlined in the 
10            paragraphs below. Projects shall be selected as 
11            follows:
12                    (A) The geographic balance of selected 
13                projects shall follow the Group classification 
14                found in the Agency's Revised Long-Term 
15                Renewable Resources Procurement Plan, with 70% 
16                of capacity allocated to projects on the Group 
17                B waitlist and 30% of capacity allocated to 
18                projects on the Group A waitlist.
19                    (B) Contract awards for waitlisted 
20                projects shall be allocated proportionate to 
21                the total nameplate capacity amount across 
22                both ordinal waitlists associated with that 
23                applicant firm or its affiliates, subject to 
24                the following conditions.
25                        (i) Each applicant firm having a 
26                    waitlisted project eligible for selection 
 
 
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1                    shall receive no less than 500 kilowatts 
2                    in awarded capacity across all groups, and 
3                    no approved vendor may receive more than 
4                    20% of each Group's waitlist allocation.
5                        (ii) Each applicant firm, upon 
6                    receiving an award of program capacity 
7                    proportionate to its waitlisted capacity, 
8                    may then determine which waitlisted 
9                    projects it chooses to be selected for a 
10                    contract award up to that capacity amount.
11                        (iii) Assuming all other program 
12                    requirements are met, applicant firms may 
13                    adjust the nameplate capacity of applicant 
14                    projects without losing waitlist 
15                    eligibility, so long as no project is 
16                    greater than 2,000 kilowatts in size.
17                        (iv) Assuming all other program 
18                    requirements are met, applicant firms may 
19                    adjust the expected production associated 
20                    with applicant projects, subject to 
21                    verification by the Program Administrator.
22                    (C) After a review of affiliate 
23                information and the current ordinal waitlists, 
24                the Agency shall announce the nameplate 
25                capacity award amounts associated with 
26                applicant firms no later than 90 days after 
 
 
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1                the effective date of this amendatory Act of 
2                the 102nd General Assembly.
3                    (D) Applicant firms shall submit their 
4                portfolio of projects used to satisfy those 
5                contract awards no less than 90 days after the 
6                Agency's announcement. The total nameplate 
7                capacity of all projects used to satisfy that 
8                portfolio shall be no greater than the 
9                Agency's nameplate capacity award amount 
10                associated with that applicant firm. An 
11                applicant firm may decline, in whole or in 
12                part, its nameplate capacity award without 
13                penalty, with such unmet capacity rolled over 
14                to the next block opening for project 
15                selection under item (iii) of subparagraph (K) 
16                of this subsection (c). Any projects not 
17                included in an applicant firm's portfolio may 
18                reapply without prejudice upon the next block 
19                reopening for project selection under item 
20                (iii) of subparagraph (K) of this subsection 
21                (c).
22                    (E) The renewable energy credit delivery 
23                contract shall be subject to the contract and 
24                payment terms outlined in item (iv) of 
25                subparagraph (L) of this subsection (c). 
26                Contract instruments used for this 
 
 
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1                subparagraph shall contain the following 
2                terms:
3                        (i) Renewable energy credit prices 
4                    shall be fixed, without further adjustment 
5                    under any other provision of this Act or 
6                    for any other reason, at 10% lower than 
7                    prices applicable to the last open block 
8                    for this category, inclusive of any adders 
9                    available for achieving a minimum of 50% 
10                    of subscribers to the project's nameplate 
11                    capacity being residential or small 
12                    commercial customers with subscriptions of 
13                    below 25 kilowatts in size;
14                        (ii) A requirement that a minimum of 
15                    50% of subscribers to the project's 
16                    nameplate capacity be residential or small 
17                    commercial customers with subscriptions of 
18                    below 25 kilowatts in size;
19                        (iii) Permission for the ability of a 
20                    contract holder to substitute projects 
21                    with other waitlisted projects without 
22                    penalty should a project receive a 
23                    non-binding estimate of costs to construct 
24                    the interconnection facilities and any 
25                    required distribution upgrades associated 
26                    with that project of greater than 30 cents 
 
 
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1                    per watt AC of that project's nameplate 
2                    capacity. In developing the applicable 
3                    contract instrument, the Agency may 
4                    consider whether other circumstances 
5                    outside of the control of the applicant 
6                    firm should also warrant project 
7                    substitution rights.
8                    The Agency shall publish a finalized 
9                updated renewable energy credit delivery 
10                contract developed consistent with these terms 
11                and conditions no less than 30 days before 
12                applicant firms must submit their portfolio of 
13                projects pursuant to item (D).
14                    (F) To be eligible for an award, the 
15                applicant firm shall certify that not less 
16                than prevailing wage, as determined pursuant 
17                to the Illinois Prevailing Wage Act, was or 
18                will be paid to employees who are engaged in 
19                construction activities associated with a 
20                selected project.
21                (4) The Agency shall open the first block of 
22            annual capacity for the category described in item 
23            (iv) of subparagraph (K) of this paragraph (1). 
24            The first block of annual capacity for item (iv) 
25            shall be for at least 50 megawatts of total 
26            nameplate capacity. Renewable energy credit prices 
 
 
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1            shall be fixed, without further adjustment under 
2            any other provision of this Act or for any other 
3            reason, at the price in the last open block in the 
4            category described in item (ii) of subparagraph 
5            (K) of this paragraph (1). Pricing for future 
6            blocks of annual capacity for this category may be 
7            adjusted in the Agency's second revision to its 
8            Long-Term Renewable Resources Procurement Plan. 
9            Projects in this category shall be subject to the 
10            contract terms outlined in item (iv) of 
11            subparagraph (L) of this paragraph (1).
12                (5) The Agency shall open the equivalent of 2 
13            years of annual capacity for the category 
14            described in item (v) of subparagraph (K) of this 
15            paragraph (1). The first block of annual capacity 
16            for item (v) shall be for at least 10 megawatts of 
17            total nameplate capacity. Notwithstanding the 
18            provisions of item (v) of subparagraph (K) of this 
19            paragraph (1), for the purpose of this initial 
20            block, the agency shall accept new project 
21            applications intended to increase the diversity of 
22            areas hosting community solar projects, the 
23            business models of projects, and the size of 
24            projects, as described by the Agency in its 
25            long-term renewable resources procurement plan 
26            that is approved as of the effective date of this 
 
 
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1            amendatory Act of the 102nd General Assembly. 
2            Projects in this category shall be subject to the 
3            contract terms outlined in item (iii) of 
4            subsection (L) of this paragraph (1).
5                (6) The Agency shall open the first blocks of 
6            annual capacity for the category described in item 
7            (vi) of subparagraph (K) of this paragraph (1), 
8            with allocations of capacity within the block 
9            generally matching the historical share of block 
10            capacity allocated between the category described 
11            in items (i) and (ii) of subparagraph (K) of this 
12            paragraph (1). The first two blocks of annual 
13            capacity for item (vi) shall be for at least 75 
14            megawatts of total nameplate capacity. The price 
15            of renewable energy credits for the blocks of 
16            capacity shall be 4% less than the price of the 
17            last open blocks in the categories described in 
18            items (i) and (ii) of subparagraph (K) of this 
19            paragraph (1). Pricing for future blocks of annual 
20            capacity for this category may be adjusted in the 
21            Agency's second revision to its Long-Term 
22            Renewable Resources Procurement Plan. Projects in 
23            this category shall be subject to the applicable 
24            contract terms outlined in items (ii) and (iii) of 
25            subparagraph (L) of this paragraph (1).
26            (v) Upon the effective date of this amendatory Act 
 
 
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1        of the 102nd General Assembly, for all competitive 
2        procurements and any procurements of renewable energy 
3        credit from new utility-scale wind and new 
4        utility-scale photovoltaic projects, the Agency shall 
5        procure indexed renewable energy credits and direct 
6        respondents to offer a strike price.
7                (1) The purchase price of the indexed 
8            renewable energy credit payment shall be 
9            calculated for each settlement period. That 
10            payment, for any settlement period, shall be equal 
11            to the difference resulting from subtracting the 
12            strike price from the index price for that 
13            settlement period. If this difference results in a 
14            negative number, the indexed REC counterparty 
15            shall owe the seller the absolute value multiplied 
16            by the quantity of energy produced in the relevant 
17            settlement period. If this difference results in a 
18            positive number, the seller shall owe the indexed 
19            REC counterparty this amount multiplied by the 
20            quantity of energy produced in the relevant 
21            settlement period.
22                (2) Parties shall cash settle every month, 
23            summing up all settlements (both positive and 
24            negative, if applicable) for the prior month.
25                (3) To ensure funding in the annual budget 
26            established under subparagraph (E) for indexed 
 
 
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1            renewable energy credit procurements for each year 
2            of the term of such contracts, which must have a 
3            minimum tenure of 20 calendar years, the 
4            procurement administrator, Agency, Commission 
5            staff, and procurement monitor shall quantify the 
6            annual cost of the contract by utilizing one or 
7            more an industry-standard, third-party forward 
8            price curves curve for energy at the appropriate 
9            hub or load zone, including the estimated 
10            magnitude and timing of the price effects related 
11            to federal carbon controls. Each forward price 
12            curve shall contain a specific value of the 
13            forecasted market price of electricity for each 
14            annual delivery year of the contract. For 
15            procurement planning purposes, the impact on the 
16            annual budget for the cost of indexed renewable 
17            energy credits for each delivery year shall be 
18            determined as the expected annual contract 
19            expenditure for that year, equaling the difference 
20            between (i) the sum across all relevant contracts 
21            of the applicable strike price multiplied by 
22            contract quantity and (ii) the sum across all 
23            relevant contracts of the forward price curve for 
24            the applicable load zone for that year multiplied 
25            by contract quantity. The contracting utility 
26            shall not assume an obligation in excess of the 
 
 
10400SB0025ham002- 195 -LRB104 07069 AAS 28576 a

1            estimated annual cost of the contracts for indexed 
2            renewable energy credits. Forward curves shall be 
3            revised on an annual basis as updated forward 
4            price curves are released and filed with the 
5            Commission in the proceeding approving the 
6            Agency's most recent long-term renewable resources 
7            procurement plan. If the expected contract spend 
8            is higher or lower than the total quantity of 
9            contracts multiplied by the forward price curve 
10            value for that year, the forward price curve shall 
11            be updated by the procurement administrator, in 
12            consultation with the Agency, Commission staff, 
13            and procurement monitors, using then-currently 
14            available price forecast data and additional 
15            budget dollars shall be obligated or reobligated 
16            as appropriate.
17                (4) To ensure that indexed renewable energy 
18            credit prices remain predictable and affordable, 
19            the Agency may consider the institution of a price 
20            collar on REC prices paid under indexed renewable 
21            energy credit procurements establishing floor and 
22            ceiling REC prices applicable to indexed REC 
23            contract prices. Any price collars applicable to 
24            indexed REC procurements shall be proposed by the 
25            Agency through its long-term renewable resources 
26            procurement plan. 
 
 
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1            (vi) All procurements under this subparagraph (G), 
2        including the procurement of renewable energy credits 
3        from hydropower facilities, shall comply with the 
4        geographic requirements in subparagraph (I) of this 
5        paragraph (1) and shall follow the procurement 
6        processes and procedures described in this Section and 
7        Section 16-111.5 of the Public Utilities Act to the 
8        extent practicable, and these processes and procedures 
9        may be expedited to accommodate the schedule 
10        established by this subparagraph (G). To ensure the 
11        successful development of new renewable energy 
12        projects supported through competitive procurements, 
13        for any procurements conducted under items (i), (ii), 
14        (iii), and (v) of this subparagraph (G) and any other 
15        procurement of new utility-scale wind or utility-scale 
16        solar projects that were entered into prior to January 
17        1, 2025, the Agency shall allow, upon a demonstration 
18        of need to ensure the commercial viability of a 
19        project, for a one-time, post-award renegotiation of 
20        select contract terms prior to the project's 
21        commercial operation date through bilateral 
22        negotiation between the Agency, the buyer, and a 
23        winning bidder. Contract terms subject to 
24        renegotiation may include the project map, as defined 
25        under the applicable competitive solicitation, the 
26        real estate footprint or any limitations thereof, the 
 
 
10400SB0025ham002- 197 -LRB104 07069 AAS 28576 a

1        location of the generators, or a potential reduction 
2        in the quantity of renewable energy credits to be 
3        delivered. Provisions related to a renewable energy 
4        credit delivery shortfall and the event of default may 
5        be replaced with similar provisions approved by the 
6        Agency in subsequent years or subsequent to a 
7        successful bid. Post-award renegotiation of 
8        competitively bid renewable energy credit contracts 
9        entered into prior to January 1, 2025 shall not be 
10        permitted to the extent such renegotiation would 
11        result in (1) the point of interconnection being 
12        within the service area of a different state, a 
13        different regional transmission organization zone, or 
14        a different regional transmission organization, (2) 
15        the generator no longer meeting the definition of the 
16        resource category for which the winning bidder was 
17        originally awarded a contract, (3) the generator no 
18        longer meeting the Agency's public interest criteria 
19        as established in the long-term renewable resources 
20        plan in effect at the time of the contract award, or 
21        (4) a change to material terms of the renewable energy 
22        credit contract unrelated to project land or footprint 
23        or the number of renewable energy credits to be 
24        delivered, including the applicable bid price or 
25        strike price. If the Agency, the buyer, and the 
26        winning bidder reach an agreement on amended terms, 
 
 
10400SB0025ham002- 198 -LRB104 07069 AAS 28576 a

1        then, upon petition by the winning bidder or current 
2        seller, the Commission shall issue an order directing 
3        the utility counterparty to execute an amendment 
4        drafted by the Agency with the revised terms to the 
5        renewable energy credit contract, the product order, 
6        or both. The Agency shall provide the amendment to the 
7        utility within 15 business days after the Commission's 
8        order, and the utility shall execute the amendment no 
9        more than 7 calendar days after delivery by the 
10        Agency.    
11            (vii) On and after the effective date of this 
12        amendatory Act of the 103rd General Assembly, for all 
13        procurements of renewable energy credits from 
14        hydropower facilities, the Agency shall establish 
15        contract terms designed to optimize existing 
16        hydropower facilities through modernization or 
17        retooling and establish new hydropower facilities at 
18        existing dams. Procurements made under this item (vii) 
19        shall prioritize projects located in designated 
20        environmental justice communities, as defined in 
21        subsection (b) of Section 1-56 of this Act, or in 
22        projects located in units of local government with 
23        median incomes that do not exceed 82% of the median 
24        income of the State. 
25        (H) The procurement of renewable energy resources for 
26    a given delivery year shall be reduced as described in 
 
 
10400SB0025ham002- 199 -LRB104 07069 AAS 28576 a

1    this subparagraph (H) if an alternative retail electric 
2    supplier meets the requirements described in this 
3    subparagraph (H). 
4            (i) Within 45 days after June 1, 2017 (the 
5        effective date of Public Act 99-906), an alternative 
6        retail electric supplier or its successor shall submit 
7        an informational filing to the Illinois Commerce 
8        Commission certifying that, as of December 31, 2015, 
9        the alternative retail electric supplier owned one or 
10        more electric generating facilities that generates 
11        renewable energy resources as defined in Section 1-10 
12        of this Act, provided that such facilities are not 
13        powered by wind or photovoltaics, and the facilities 
14        generate one renewable energy credit for each 
15        megawatthour of energy produced from the facility.
16            The informational filing shall identify each 
17        facility that was eligible to satisfy the alternative 
18        retail electric supplier's obligations under Section 
19        16-115D of the Public Utilities Act as described in 
20        this item (i).
21            (ii) For a given delivery year, the alternative 
22        retail electric supplier may elect to supply its 
23        retail customers with renewable energy credits from 
24        the facility or facilities described in item (i) of 
25        this subparagraph (H) that continue to be owned by the 
26        alternative retail electric supplier.
 
 
10400SB0025ham002- 200 -LRB104 07069 AAS 28576 a

1            (iii) The alternative retail electric supplier 
2        shall notify the Agency and the applicable utility, no 
3        later than February 28 of the year preceding the 
4        applicable delivery year or 15 days after June 1, 2017 
5        (the effective date of Public Act 99-906), whichever 
6        is later, of its election under item (ii) of this 
7        subparagraph (H) to supply renewable energy credits to 
8        retail customers of the utility. Such election shall 
9        identify the amount of renewable energy credits to be 
10        supplied by the alternative retail electric supplier 
11        to the utility's retail customers and the source of 
12        the renewable energy credits identified in the 
13        informational filing as described in item (i) of this 
14        subparagraph (H), subject to the following 
15        limitations:
16                For the delivery year beginning June 1, 2018, 
17            the maximum amount of renewable energy credits to 
18            be supplied by an alternative retail electric 
19            supplier under this subparagraph (H) shall be 68% 
20            multiplied by 25% multiplied by 14.5% multiplied 
21            by the amount of metered electricity 
22            (megawatt-hours) delivered by the alternative 
23            retail electric supplier to Illinois retail 
24            customers during the delivery year ending May 31, 
25            2016.
26                For delivery years beginning June 1, 2019 and 
 
 
10400SB0025ham002- 201 -LRB104 07069 AAS 28576 a

1            each year thereafter, the maximum amount of 
2            renewable energy credits to be supplied by an 
3            alternative retail electric supplier under this 
4            subparagraph (H) shall be 68% multiplied by 50% 
5            multiplied by 16% multiplied by the amount of 
6            metered electricity (megawatt-hours) delivered by 
7            the alternative retail electric supplier to 
8            Illinois retail customers during the delivery year 
9            ending May 31, 2016, provided that the 16% value 
10            shall increase by 1.5% each delivery year 
11            thereafter to 25% by the delivery year beginning 
12            June 1, 2025, and thereafter the 25% value shall 
13            apply to each delivery year.
14            For each delivery year, the total amount of 
15        renewable energy credits supplied by all alternative 
16        retail electric suppliers under this subparagraph (H) 
17        shall not exceed 9% of the Illinois target renewable 
18        energy credit quantity. The Illinois target renewable 
19        energy credit quantity for the delivery year beginning 
20        June 1, 2018 is 14.5% multiplied by the total amount of 
21        metered electricity (megawatt-hours) delivered in the 
22        delivery year immediately preceding that delivery 
23        year, provided that the 14.5% shall increase by 1.5% 
24        each delivery year thereafter to 25% by the delivery 
25        year beginning June 1, 2025, and thereafter the 25% 
26        value shall apply to each delivery year.
 
 
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1            If the requirements set forth in items (i) through 
2        (iii) of this subparagraph (H) are met, the charges 
3        that would otherwise be applicable to the retail 
4        customers of the alternative retail electric supplier 
5        under paragraph (6) of this subsection (c) for the 
6        applicable delivery year shall be reduced by the ratio 
7        of the quantity of renewable energy credits supplied 
8        by the alternative retail electric supplier compared 
9        to that supplier's target renewable energy credit 
10        quantity. The supplier's target renewable energy 
11        credit quantity for the delivery year beginning June 
12        1, 2018 is 14.5% multiplied by the total amount of 
13        metered electricity (megawatt-hours) delivered by the 
14        alternative retail supplier in that delivery year, 
15        provided that the 14.5% shall increase by 1.5% each 
16        delivery year thereafter to 25% by the delivery year 
17        beginning June 1, 2025, and thereafter the 25% value 
18        shall apply to each delivery year. 
19            On or before April 1 of each year, the Agency shall 
20        annually publish a report on its website that 
21        identifies the aggregate amount of renewable energy 
22        credits supplied by alternative retail electric 
23        suppliers under this subparagraph (H). 
24        (I) The Agency shall design its long-term renewable 
25    energy procurement plan to maximize the State's interest 
26    in the health, safety, and welfare of its residents, 
 
 
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1    including but not limited to minimizing sulfur dioxide, 
2    nitrogen oxide, particulate matter and other pollution 
3    that adversely affects public health in this State, 
4    increasing fuel and resource diversity in this State, 
5    enhancing the reliability and resiliency of the 
6    electricity distribution system in this State, meeting 
7    goals to limit carbon dioxide emissions under federal or 
8    State law, and contributing to a cleaner and healthier 
9    environment for the citizens of this State. In order to 
10    further these legislative purposes, renewable energy 
11    credits shall be eligible to be counted toward the 
12    renewable energy requirements of this subsection (c) if 
13    they are generated from facilities located in this State. 
14    The Agency may qualify renewable energy credits from 
15    facilities located in states adjacent to Illinois or 
16    renewable energy credits associated with the electricity 
17    generated by a utility-scale wind energy facility or 
18    utility-scale photovoltaic facility and transmitted by a 
19    qualifying direct current project described in subsection 
20    (b-5) of Section 8-406 of the Public Utilities Act to a 
21    delivery point on the electric transmission grid located 
22    in this State or a state adjacent to Illinois, if the 
23    generator demonstrates and the Agency determines that the 
24    operation of such facility or facilities will help promote 
25    the State's interest in the health, safety, and welfare of 
26    its residents based on the public interest criteria 
 
 
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1    described above. For the purposes of this Section, 
2    renewable resources that are delivered via a high voltage 
3    direct current converter station located in Illinois shall 
4    be deemed generated in Illinois at the time and location 
5    the energy is converted to alternating current by the high 
6    voltage direct current converter station if the high 
7    voltage direct current transmission line: (i) after the 
8    effective date of this amendatory Act of the 102nd General 
9    Assembly, was constructed with a project labor agreement; 
10    (ii) is capable of transmitting electricity at 525kv; 
11    (iii) has an Illinois converter station located and 
12    interconnected in the region of the PJM Interconnection, 
13    LLC; (iv) does not operate as a public utility; and (v) if 
14    the high voltage direct current transmission line was 
15    energized after June 1, 2023. To ensure that the public 
16    interest criteria are applied to the procurement and given 
17    full effect, the Agency's long-term procurement plan shall 
18    describe in detail how each public interest factor shall 
19    be considered and weighted for facilities located in 
20    states adjacent to Illinois.
21        (J) In order to promote the competitive development of 
22    renewable energy resources in furtherance of the State's 
23    interest in the health, safety, and welfare of its 
24    residents, renewable energy credits shall not be eligible 
25    to be counted toward the renewable energy requirements of 
26    this subsection (c) if they are sourced from a generating 
 
 
10400SB0025ham002- 205 -LRB104 07069 AAS 28576 a

1    unit whose costs were being recovered through rates 
2    regulated by this State or any other state or states on or 
3    after January 1, 2017. Each contract executed to purchase 
4    renewable energy credits under this subsection (c) shall 
5    provide for the contract's termination if the costs of the 
6    generating unit supplying the renewable energy credits 
7    subsequently begin to be recovered through rates regulated 
8    by this State or any other state or states; and each 
9    contract shall further provide that, in that event, the 
10    supplier of the credits must return 110% of all payments 
11    received under the contract. Amounts returned under the 
12    requirements of this subparagraph (J) shall be retained by 
13    the utility and all of these amounts shall be used for the 
14    procurement of additional renewable energy credits from 
15    new wind or new photovoltaic resources as defined in this 
16    subsection (c). The long-term plan shall provide that 
17    these renewable energy credits shall be procured in the 
18    next procurement event.
19        Notwithstanding the limitations of this subparagraph 
20    (J), renewable energy credits sourced from generating 
21    units that are constructed, purchased, owned, or leased by 
22    an electric utility as part of an approved project, 
23    program, or pilot under Section 1-56 of this Act shall be 
24    eligible to be counted toward the renewable energy 
25    requirements of this subsection (c), regardless of how the 
26    costs of these units are recovered. As long as a 
 
 
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1    generating unit or an identifiable portion of a generating 
2    unit has not had and does not have its costs recovered 
3    through rates regulated by this State or any other state, 
4    HVDC renewable energy credits associated with that 
5    generating unit or identifiable portion thereof shall be 
6    eligible to be counted toward the renewable energy 
7    requirements of this subsection (c). 
8        (K) The long-term renewable resources procurement plan 
9    developed by the Agency in accordance with subparagraph 
10    (A) of this paragraph (1) shall include an Adjustable 
11    Block program for the procurement of renewable energy 
12    credits from new photovoltaic projects that are 
13    distributed renewable energy generation devices or new 
14    photovoltaic community renewable generation projects. The 
15    Adjustable Block program shall be generally designed to 
16    provide for the steady, predictable, and sustainable 
17    growth of new solar photovoltaic development in Illinois. 
18    To this end, the Adjustable Block program shall provide a 
19    transparent annual schedule of prices and quantities to 
20    enable the photovoltaic market to scale up and for 
21    renewable energy credit prices to adjust at a predictable 
22    rate over time. The prices set by the Adjustable Block 
23    program can be reflected as a set value or as the product 
24    of a formula.
25        The Adjustable Block program shall include for each 
26    category of eligible projects for each delivery year: a 
 
 
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1    single block of nameplate capacity, a price for renewable 
2    energy credits within that block, and the terms and 
3    conditions for securing a spot on a waitlist once the 
4    block is fully committed or reserved. Except as outlined 
5    below, the waitlist of projects in a given year will carry 
6    over to apply to the subsequent year when another block is 
7    opened. Only projects energized on or after June 1, 2017 
8    shall be eligible for the Adjustable Block program. For 
9    each category for each delivery year the Agency shall 
10    determine the amount of generation capacity in each block, 
11    and the purchase price for each block, provided that the 
12    purchase price provided and the total amount of generation 
13    in all blocks for all categories shall be sufficient to 
14    meet the goals in this subsection (c). The Agency shall 
15    strive to issue a single block sized to provide for 
16    stability and market growth. The Agency shall establish 
17    program eligibility requirements that ensure that projects 
18    that enter the program are sufficiently mature to indicate 
19    a demonstrable path to completion. The Agency may 
20    periodically review its prior decisions establishing the 
21    amount of generation capacity in each block, and the 
22    purchase price for each block, and may propose, on an 
23    expedited basis, changes to these previously set values, 
24    including but not limited to redistributing these amounts 
25    and the available funds as necessary and appropriate, 
26    subject to Commission approval as part of the periodic 
 
 
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1    plan revision process described in Section 16-111.5 of the 
2    Public Utilities Act. The Agency may define different 
3    block sizes, purchase prices, or other distinct terms and 
4    conditions for projects located in different utility 
5    service territories if the Agency deems it necessary to 
6    meet the goals in this subsection (c).
7        The Adjustable Block program shall include the 
8    following categories in at least the following amounts:
9            (i) At least 20% from distributed renewable energy 
10        generation devices with a nameplate capacity of no 
11        more than 25 kilowatts.
12            (ii) At least 20% from distributed renewable 
13        energy generation devices with a nameplate capacity of 
14        more than 25 kilowatts and no more than 5,000 
15        kilowatts. The Agency may create sub-categories within 
16        this category to account for the differences between 
17        projects for small commercial customers, large 
18        commercial customers, and public or non-profit 
19        customers. A project shall not be colocated with one 
20        or more other distributed renewable energy generation 
21        projects if the aggregate nameplate capacity of the 
22        projects exceeds 5,000 kilowatts AC. Notwithstanding 
23        any other provision of this Section, if 2 or more 
24        projects are developed, owned, or controlled by or 
25        originate from the same developer or an affiliated 
26        developer and the projects serve affiliated loads, the 
 
 
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1        projects shall be colocated if the projects are 
2        located on adjacent parcels. If 2 or more projects are 
3        developed, owned, or controlled by or originate from 
4        the same developer and the projects serve unaffiliated 
5        loads, the projects may be colocated if documentation 
6        indicates affiliated management and ownership in the 
7        pre-development, development, construction, and 
8        management of the projects and the projects are 
9        located on a single or adjacent parcels. 
10        Notwithstanding any subsequent transfer, assignment, 
11        or conveyance of ownership or development rights to 
12        separate legal entities, the Agency shall consider, in 
13        its determination of whether projects are affiliated, 
14        evidence that the projects were pre-developed by the 
15        same legal entity or an affiliated entity. If the 
16        Agency determines the projects are affiliated, the 
17        projects shall be treated as colocated for purposes of 
18        aggregate nameplate capacity limitations and renewable 
19        energy credit pricing adjustments. The Agency shall 
20        make exceptions on a case-by-case basis if it is 
21        demonstrated that projects on one parcel or projects 
22        on adjacent parcels are unaffiliated. For purposes of 
23        determining colocation, an approved vendor who submits 
24        an application for a distributed renewable energy 
25        generation project shall be required to submit an 
26        affidavit attesting that the project is not affiliated 
 
 
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1        with any other distributed renewable energy generation 
2        project such that, if the 2 projects were deemed 
3        colocated, the projects would exceed the 5,000 
4        kilowatts nameplate capacity limitation. The receipt 
5        of an affidavit shall not restrict the Agency's 
6        ability to investigate and determine whether the 
7        project is, in fact, colocated.
8            For purposes of this item (ii):
9            "Affiliate" has the meaning given to that term in 
10        subitem (3) of item (iii) of this subparagraph (K).
11            "Colocated" means 2 or more distributed renewable 
12        energy generation projects that are located on a 
13        single parcel, except for projects where the owner of 
14        the applicable retail electric account is confirmed to 
15        be unaffiliated and the projects serve distinct 
16        electrical loads.
17            "Control" has the meaning given to that term in 
18        subitem (3) of item (iii) of this subparagraph (K).
19            (iii) At least 30% from photovoltaic community 
20        renewable generation projects. Capacity for this 
21        category for the first 2 delivery years after the 
22        effective date of this amendatory Act of the 102nd 
23        General Assembly shall be allocated to waitlist 
24        projects as provided in paragraph (3) of item (iv) of 
25        subparagraph (G). Starting in the third delivery year 
26        after the effective date of this amendatory Act of the 
 
 
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1        102nd General Assembly or earlier if the Agency 
2        determines there is additional capacity needed for to 
3        meet previous delivery year requirements, the 
4        following shall apply:
5                (1) the Agency shall select projects on a 
6            first-come, first-serve basis, however the Agency 
7            may suggest additional methods to prioritize 
8            projects that are submitted at the same time;
9                (2) projects shall have subscriptions of 25 kW 
10            or less for at least 50% of the facility's 
11            nameplate capacity and the Agency shall price the 
12            renewable energy credits with that as a factor;
13                (3) projects shall not be colocated with one 
14            or more other community renewable generation 
15            projects such that the aggregate nameplate 
16            capacity exceeds 5,000 kilowatts. The total 
17            nameplate capacity of colocated projects shall be 
18            the sum of the nameplate capacities of the 
19            individual projects. For purposes of this subitem 
20            (3), separate legal formation of approved vendors, 
21            owners, or developers shall not preclude a finding 
22            of affiliation by the Agency. Evidence of 
23            affiliation may include, but is not limited to, 
24            shared personnel, common contractual or financing 
25            arrangements, a shared interconnection agreement, 
26            distinct interconnection agreements obtained by 
 
 
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1            the same pre-development entity that are 
2            subsequently sold to distinct legal entities, 
3            familial relationships, or any demonstrable 
4            pattern of coordinated action in the 
5            pre-development, development, construction, or 
6            management of community renewable generation 
7            projects.
8                The Agency shall determine affiliation based 
9            on evidence that projects either (i) share a 
10            common origin on a parcel that has been subdivided 
11            in the 5 years before the date of application or 
12            (ii) were pre-developed before the beginning of 
13            construction by the same legal entity or an 
14            affiliated legal entity. The determination shall 
15            be made notwithstanding any subsequent transfer, 
16            assignment, or conveyance of ownership or 
17            development rights to separate legal entities. If 
18            the Agency determines the projects are affiliated, 
19            the projects shall be treated as colocated for the 
20            purposes of aggregate nameplate capacity 
21            limitations and renewable energy credit pricing 
22            adjustments. The Agency shall make exceptions to 
23            this subitem (3) on a case-by-case basis if it is 
24            demonstrated that projects on one parcel or 
25            projects on adjacent parcels are unaffiliated.
26                A parcel shall not be divided into multiple 
 
 
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1            parcels within the 5 years before the submission 
2            of a project application. If a parcel is divided 
3            within the preceding 5 years, a colocation 
4            determination shall be made based on the 
5            boundaries of the previous undivided parcel.
6                For purposes of determining colocation, an 
7            approved vendor who submits an application for a 
8            community renewable generation project shall be 
9            required to submit an affidavit attesting that (i) 
10            the parcel on which the project is sited has not 
11            been subdivided within the 5 years preceding the 
12            project application and (ii) the project is not 
13            affiliated with any other community renewable 
14            energy project in a manner that would cause the 2 
15            projects, if deemed colocated, to exceed the 5,000 
16            kilowatt nameplate capacity limitation. The 
17            receipt of an affidavit shall not restrict the 
18            Agency's ability to investigate and determine 
19            whether the project is colocated.
20                Multiple community solar projects sited on 
21            distinct structures located on a single parcel 
22            shall be considered colocated and must demonstrate 
23            that the projects are unaffiliated in order to not 
24            be considered colocated. Each colocated project 
25            shall receive the renewable energy credit price 
26            corresponding to the total, aggregated nameplate 
 
 
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1            capacity of the colocated systems, as determined 
2            at the time the second project's application is 
3            submitted to the Agency. If the second colocated 
4            project has been constructed and placed in service 
5            prior to application, and was placed in service 
6            more than 2 years after Commission approval of the 
7            original project, the colocation pricing 
8            adjustment shall not apply, and each project shall 
9            receive the standalone renewable energy credit 
10            price for its individual capacity.    
11                For purposes of this subitem (3):
12                "Affiliate" means any other entity that, 
13            directly or indirectly through one or more 
14            intermediaries, is controlled by or is under 
15            common control of the primary entity or a third 
16            entity. "Affiliate" includes family members for 
17            the purposes of colocation between projects. 
18            "Affiliate" does not include entities that have 
19            shared sales or revenue-sharing arrangements or 
20            common debt and equity financing arrangements.
21                "Colocated" means 2 or more community 
22            renewable generation projects located on a single 
23            parcel or adjacent parcels, unless it is 
24            demonstrated that the projects are developed by 
25            unaffiliated entities.
26                "Control" means the possession, directly or 
 
 
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1            indirectly, of the power to direct the management 
2            and policies of an entity , as defined in the 
3            Agency's first revised long-term renewable 
4            resources procurement plan approved by the 
5            Commission on February 18, 2020, such that the 
6            aggregate nameplate capacity exceeds 5,000 
7            kilowatts; and
8                (4) projects greater than 2 MW may not apply 
9            until after the approval of the Agency's revised 
10            Long-Term Renewable Resources Procurement Plan 
11            after the effective date of this amendatory Act of 
12            the 102nd General Assembly. 
13            (iv) At least 15% from distributed renewable 
14        generation devices or photovoltaic community renewable 
15        generation projects installed on public school land. 
16        The Agency may create subcategories within this 
17        category to account for the differences between 
18        project size or location. Projects located within 
19        environmental justice communities or within 
20        Organizational Units that fall within Tier 1 or Tier 2 
21        shall be given priority. Each of the Agency's periodic 
22        updates to its long-term renewable resources 
23        procurement plan to incorporate the procurement 
24        described in this subparagraph (iv) shall also include 
25        the proposed quantities or blocks, pricing, and 
26        contract terms applicable to the procurement as 
 
 
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1        indicated herein. In each such update and procurement, 
2        the Agency shall set the renewable energy credit price 
3        and establish payment terms for the renewable energy 
4        credits procured pursuant to this subparagraph (iv) 
5        that make it feasible and affordable for public 
6        schools to install photovoltaic distributed renewable 
7        energy devices on their premises, including, but not 
8        limited to, those public schools subject to the 
9        prioritization provisions of this subparagraph. For 
10        the purposes of this item (iv):
11            "Environmental Justice Community" shall have the 
12        same meaning set forth in the Agency's long-term 
13        renewable resources procurement plan;
14            "Organization Unit", "Tier 1" and "Tier 2" shall 
15        have the meanings set for in Section 18-8.15 of the 
16        School Code;
17            "Public schools" shall have the meaning set forth 
18        in Section 1-3 of the School Code and includes public 
19        institutions of higher education, as defined in the 
20        Board of Higher Education Act.
21            (v) At least 5% from community-driven community 
22        solar projects intended to provide more direct and 
23        tangible connection and benefits to the communities 
24        which they serve or in which they operate and, 
25        additionally, to increase the variety of community 
26        solar locations, models, and options in Illinois. As 
 
 
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1        part of its long-term renewable resources procurement 
2        plan, the Agency shall develop selection criteria for 
3        projects participating in this category. Nothing in 
4        this Section shall preclude the Agency from creating a 
5        selection process that maximizes community ownership 
6        and community benefits in selecting projects to 
7        receive renewable energy credits. Selection criteria 
8        shall include:
9                (1) community ownership or community 
10            wealth-building;
11                (2) additional direct and indirect community 
12            benefit, beyond project participation as a 
13            subscriber, including, but not limited to, 
14            economic, environmental, social, cultural, and 
15            physical benefits;
16                (3) meaningful involvement in project 
17            organization and development by community members 
18            or nonprofit organizations or public entities 
19            located in or serving the community;
20                (4) engagement in project operations and 
21            management by nonprofit organizations, public 
22            entities, or community members; and
23                (5) whether a project is developed in response 
24            to a site-specific RFP developed by community 
25            members or a nonprofit organization or public 
26            entity located in or serving the community.
 
 
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1            Selection criteria may also prioritize projects 
2        that:
3                (1) are developed in collaboration with or to 
4            provide complementary opportunities for the Clean 
5            Jobs Workforce Network Program, the Illinois 
6            Climate Works Preapprenticeship Program, the 
7            Returning Residents Clean Jobs Training Program, 
8            the Clean Energy Contractor Incubator Program, or 
9            the Clean Energy Primes Contractor Accelerator 
10            Program;
11                (2) increase the diversity of locations of 
12            community solar projects in Illinois, including by 
13            locating in urban areas and population centers;
14                (3) are located in Equity Investment Eligible 
15            Communities;
16                (4) are not greenfield projects;
17                (5) serve only local subscribers;
18                (6) have a nameplate capacity that does not 
19            exceed 500 kW;
20                (7) are developed by an equity eligible 
21            contractor; or
22                (8) otherwise meaningfully advance the goals 
23            of providing more direct and tangible connection 
24            and benefits to the communities which they serve 
25            or in which they operate and increasing the 
26            variety of community solar locations, models, and 
 
 
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1            options in Illinois.
2            For the purposes of this item (v):
3            "Community" means a social unit in which people 
4        come together regularly to effect change; a social 
5        unit in which participants are marked by a cooperative 
6        spirit, a common purpose, or shared interests or 
7        characteristics; or a space understood by its 
8        residents to be delineated through geographic 
9        boundaries or landmarks.
10            "Community benefit" means a range of services and 
11        activities that provide affirmative, economic, 
12        environmental, social, cultural, or physical value to 
13        a community; or a mechanism that enables economic 
14        development, high-quality employment, and education 
15        opportunities for local workers and residents, or 
16        formal monitoring and oversight structures such that 
17        community members may ensure that those services and 
18        activities respond to local knowledge and needs.
19            "Community ownership" means an arrangement in 
20        which an electric generating facility is, or over time 
21        will be, in significant part, owned collectively by 
22        members of the community to which an electric 
23        generating facility provides benefits; members of that 
24        community participate in decisions regarding the 
25        governance, operation, maintenance, and upgrades of 
26        and to that facility; and members of that community 
 
 
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1        benefit from regular use of that facility.
2            Terms and guidance within these criteria that are 
3        not defined in this item (v) shall be defined by the 
4        Agency, with stakeholder input, during the development 
5        of the Agency's long-term renewable resources 
6        procurement plan. The Agency shall develop regular 
7        opportunities for projects to submit applications for 
8        projects under this category, and develop selection 
9        criteria that gives preference to projects that better 
10        meet individual criteria as well as projects that 
11        address a higher number of criteria.
12            (vi) At least 10% from distributed renewable 
13        energy generation devices, which includes distributed 
14        renewable energy devices with a nameplate capacity 
15        under 5,000 kilowatts or photovoltaic community 
16        renewable generation projects, from applicants that 
17        are equity eligible contractors. The Agency may create 
18        subcategories within this category to account for the 
19        differences between project size and type. The Agency 
20        shall propose to increase the percentage in this item 
21        (vi) over time to 40% based on factors, including, but 
22        not limited to, the number of equity eligible 
23        contractors and capacity used in this item (vi) in 
24        previous delivery years.
25            The Agency shall propose a payment structure for 
26        contracts executed pursuant to this paragraph under 
 
 
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1        which, upon a demonstration of qualification or need 
2        under criteria established by the Agency that is 
3        focused on supporting small and emerging businesses 
4        and businesses that most acutely face barriers to the 
5        access of capital, applicant firms are advanced 
6        capital disbursed after contract execution but before 
7        the contracted project's energization. The amount or 
8        percentage of capital advanced prior to project 
9        energization shall be sufficient to both cover any 
10        increase in development costs resulting from 
11        prevailing wage requirements or project-labor 
12        agreements, and designed to overcome barriers in 
13        access to capital faced by equity eligible 
14        contractors. The amount or percentage of advanced 
15        capital may vary by subcategory within this category 
16        and by an applicant's demonstration of need, with such 
17        levels to be established through the Long-Term 
18        Renewable Resources Procurement Plan authorized under 
19        subparagraph (A) of paragraph (1) of subsection (c) of 
20        this Section and any application requirements or 
21        evaluation criteria developed pursuant to the Plan.
22            Contracts developed featuring capital advanced 
23        prior to a project's energization shall feature 
24        provisions to ensure both the successful development 
25        of applicant projects and the delivery of the 
26        renewable energy credits for the full term of the 
 
 
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1        contract, including ongoing collateral requirements 
2        and other provisions deemed necessary by the Agency, 
3        and may include energization timelines longer than for 
4        comparable project types. The percentage or amount of 
5        capital advanced prior to project energization shall 
6        not operate to increase the overall contract value, 
7        however contracts executed under this subparagraph may 
8        feature renewable energy credit prices higher than 
9        those offered to similar projects participating in 
10        other categories. Capital advanced prior to 
11        energization shall serve to reduce the ratable 
12        payments made after energization under items (ii) and 
13        (iii) of subparagraph (L) or payments made for each 
14        renewable energy credit delivery under item (iv) of 
15        subparagraph (L). 
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 
 
 
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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), and the Agency shall retain the 
26    consultant or consultants in the same manner, to the 
 
 
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1    extent practicable, as the Agency retains others to 
2    administer provisions of this Act, including, but not 
3    limited to, the procurement administrator. The selection 
4    of experts and expert consulting firms and the procurement 
5    process described in this subparagraph (M) are exempt from 
6    the requirements of Section 20-10 of the Illinois 
7    Procurement Code, under Section 20-10 of that Code. The 
8    Agency shall strive to minimize administrative expenses in 
9    the implementation of the Adjustable Block program.
10        The Program Administrator may charge application fees 
11    to participating firms to cover the cost of program 
12    administration. Any application fee amounts shall 
13    initially be determined through the long-term renewable 
14    resources procurement plan, and modifications to any 
15    application fee that deviate more than 25% from the 
16    Commission's approved value must be approved by the 
17    Commission as a long-term plan revision under Section 
18    16-111.5 of the Public Utilities Act. The Agency shall 
19    consider stakeholder feedback when making adjustments to 
20    application fees and shall notify stakeholders in advance 
21    of any planned changes. 
22        In addition to covering the costs of program 
23    administration, the Agency, in conjunction with its 
24    Program Administrator, may also use the proceeds of such 
25    fees charged to participating firms to support public 
26    education and ongoing regional and national coordination 
 
 
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1    with nonprofit organizations, public bodies, and others 
2    engaged in the implementation of renewable energy 
3    incentive programs or similar initiatives. This work may 
4    include developing papers and reports, hosting regional 
5    and national conferences, and other work deemed necessary 
6    by the Agency to position the State of Illinois as a 
7    national leader in renewable energy incentive program 
8    development and administration. 
9        The Agency and its consultant or consultants shall 
10    monitor block activity, share program activity with 
11    stakeholders and conduct quarterly meetings to discuss 
12    program activity and market conditions. If necessary, the 
13    Agency may make prospective administrative adjustments to 
14    the Adjustable Block program design, such as making 
15    adjustments to purchase prices as necessary to achieve the 
16    goals of this subsection (c). Program modifications to any 
17    block price that do not deviate from the Commission's 
18    approved value by more than 10% shall take effect 
19    immediately and are not subject to Commission review and 
20    approval. Program modifications to any block price that 
21    deviate more than 10% from the Commission's approved value 
22    must be approved by the Commission as a long-term plan 
23    amendment under Section 16-111.5 of the Public Utilities 
24    Act. The Agency shall consider stakeholder feedback when 
25    making adjustments to the Adjustable Block design and 
26    shall notify stakeholders in advance of any planned 
 
 
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1    changes.
2        The Agency and its program administrators for both the 
3    Adjustable Block program and the Illinois Solar for All 
4    Program, consistent with the requirements of this 
5    subsection (c) and subsection (b) of Section 1-56 of this 
6    Act, shall propose the Adjustable Block program terms, 
7    conditions, and requirements, including the prices to be 
8    paid for renewable energy credits, where applicable, and 
9    requirements applicable to participating entities and 
10    project applications, through the development, review, and 
11    approval of the Agency's long-term renewable resources 
12    procurement plan described in this subsection (c) and 
13    paragraph (5) of subsection (b) of Section 16-111.5 of the 
14    Public Utilities Act. Terms, conditions, and requirements 
15    for program participation shall include the following:
16            (i) The Agency shall establish a registration 
17        process for entities seeking to qualify for 
18        program-administered incentive funding and establish 
19        baseline qualifications for vendor approval. The 
20        Agency shall also establish program requirements and 
21        minimum contract terms for vendors and others involved 
22        in the marketing, sale, installation, and financing of 
23        distributed generation systems and community solar 
24        subscriptions to prevent misleading marketing and 
25        abusive practices and to otherwise protect customers.    
26        The Agency must maintain a list of approved entities 
 
 
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1        on each program's website, and may revoke a vendor's 
2        ability to receive program-administered incentive 
3        funding status upon a determination that the vendor 
4        failed to comply with contract terms, the law, or 
5        other program requirements.
6            (ii) The Agency shall establish program 
7        requirements and minimum contract terms to ensure 
8        projects are properly installed and produce their 
9        expected amounts of energy. Program requirements may 
10        include on-site inspections and photo documentation of 
11        projects under construction. The Agency may require 
12        repairs, alterations, or additions to remedy any 
13        material deficiencies discovered. Vendors who have a 
14        disproportionately high number of deficient systems 
15        may lose their eligibility to continue to receive 
16        State-administered incentive funding through Agency 
17        programs and procurements.
18            (iii) To discourage deceptive marketing or other 
19        bad faith business practices, the Agency may require 
20        direct program participants, including agents 
21        operating on their behalf, to provide standardized 
22        disclosures to a customer prior to that customer's 
23        execution of a contract for the development of a 
24        distributed generation system or a subscription to a 
25        community solar project.
26            (iv) The Agency shall establish one or multiple 
 
 
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1        Consumer Complaints Centers to accept complaints 
2        regarding businesses that participate in, or otherwise 
3        benefit from, State-administered incentive funding 
4        through Agency-administered programs. The Agency shall 
5        maintain a public database of complaints with any 
6        confidential or particularly sensitive information 
7        redacted from public entries.
8            (v) Through a filing in the proceeding for the 
9        approval of its long-term renewable energy resources 
10        procurement plan, the Agency shall provide an annual 
11        written report to the Illinois Commerce Commission 
12        documenting the frequency and nature of complaints and 
13        any enforcement actions taken in response to those 
14        complaints.
15            (vi) The Agency shall schedule regular meetings 
16        with representatives of the Office of the Attorney 
17        General, the Illinois Commerce Commission, consumer 
18        protection groups, and other interested stakeholders 
19        to share relevant information about consumer 
20        protection, project compliance, and complaints 
21        received.
22            (vii) To the extent that complaints received 
23        implicate the jurisdiction of the Office of the 
24        Attorney General, the Illinois Commerce Commission, or 
25        local, State, or federal law enforcement, the Agency 
26        shall also refer complaints to those entities as 
 
 
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1        appropriate. 
2            (viii) The Agency shall establish a registration 
3        process for entities that provide financing for 
4        consumers for the purchase of distributed renewable 
5        generation devices. The Agency may establish baseline 
6        qualifications for financier approval, including 
7        defining the circumstances under which financing 
8        parties may be subject to registration. The Agency 
9        shall also establish program requirements for entities 
10        that provide financing for the purchase of distributed 
11        renewable generation devices, which may include 
12        marketing and disclosure requirements, other 
13        requirements as further defined by the Agency through 
14        its long-term plan, and any consumer protection 
15        requirements developed or modified thereto. The Agency 
16        shall maintain a list of approved financiers on each 
17        program's website and may revoke a financier's 
18        approval in a program upon a determination that the 
19        financier failed to comply with contract terms, the 
20        law, or other program requirements. The Agency may 
21        establish program requirements that prohibit 
22        distributed renewable generation devices intending to 
23        apply for program-administered incentive funding from 
24        receiving program funding the consumer's purchase if 
25        the device was financed by an entity whose approval 
26        status in the program has been revoked.
 
 
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1            (ix) The Agency may propose that vendors, as part 
2        of the application and annual recertification process, 
3        present the Agency or its designee with a security 
4        bond equal to an amount determined to be reasonable by 
5        the Agency. The bond shall be for the benefit of 
6        customers harmed by the vendor's violation of Agency 
7        requirements or other applicable laws or regulations. 
8        The Agency may determine that it is reasonable to have 
9        no bond requirement for some categories of vendors or 
10        enhanced bond requirements for vendors that the Agency 
11        has deemed to pose more acute risks.
12            (x) For distributed renewable generation devices, 
13        the Agency may, in its discretion, establish 
14        provisions that restrict, prohibit, or create 
15        additional requirements for distributed renewable 
16        generation device sales or financing offers through 
17        which the customer is promised the pass-through of a 
18        portion or all of the payments received by the 
19        approved vendor for the delivery of renewable energy 
20        credits only after the receipt of such payment by the 
21        approved vendor. The requirements may include the use 
22        of an escrow process developed by the Agency through 
23        which renewable energy credit payments are made to an 
24        escrow agent who then disburses the promised amount to 
25        the customer and the remainder to the vendor. The 
26        requirements in this item (x) shall in no way prohibit 
 
 
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1        the upfront discounting of the purchase price, lease 
2        payment, or power purchase agreement rate based on the 
3        anticipated receipt of renewable energy credit 
4        contract payments by the approved vendor.
5            (xi) To the extent that distributed renewable 
6        generation device sales or financing offers through 
7        which the customer is promised the pass-through of a 
8        portion or all of the payments received by the vendor 
9        for the delivery of renewable energy credits after the 
10        receipt of such payment by the vendor are permitted, 
11        the following requirements shall apply in a time and 
12        manner determined by the Agency:
13                (I) the vendor shall submit proof of customer 
14            payments to the Agency as the Agency deems 
15            necessary; and
16                (II) the vendor shall represent and warrant on 
17            a form developed by the Agency that the vendor is 
18            not insolvent, has not voluntarily filed for 
19            bankruptcy, and has not been subject to or 
20            threatened with involuntary insolvency.
21            (xii) To ensure that customers receive full and 
22        uninterrupted benefits and services promised by 
23        vendors, the Agency may propose additional solutions 
24        through its long-term renewable resources procurement 
25        plan described in this subsection (c) and paragraph 
26        (5) of subsection (b) of Section 16-111.5 of the 
 
 
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1        Public Utilities Act. The solutions may allow for 
2        collections made pursuant to subsection (k) of Section 
3        16-108 of the Public Utilities Act to support the 
4        programs and procurements outlined in paragraph (1) of 
5        subsection (c) of this Section to be leveraged to (1) 
6        ensure that a vendor's promised payments are received 
7        by customers, (2) incentivize vendors to establish 
8        service agreements with customers whose original 
9        vendor has become nonresponsive, (3) ensure that 
10        customers receive restitution for financial harm 
11        proven to be caused by a program vendor or its 
12        designee, or (4) otherwise ensure that customers do 
13        not suffer loss or harm through activities supported 
14        by the Adjustable Block program and the Illinois Solar 
15        for All Program.    
16        (N) The Agency shall establish the terms, conditions, 
17    and program requirements for photovoltaic community 
18    renewable generation projects with a goal to expand access 
19    to a broader group of energy consumers, to ensure robust 
20    participation opportunities for residential and small 
21    commercial customers and those who cannot install 
22    renewable energy on their own properties. Subject to 
23    reasonable limitations, any plan approved by the 
24    Commission shall allow subscriptions to community 
25    renewable generation projects to be portable and 
26    transferable. For purposes of this subparagraph (N), 
 
 
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1    "portable" means that subscriptions may be retained by the 
2    subscriber even if the subscriber relocates or changes its 
3    address within the same utility service territory; and 
4    "transferable" means that a subscriber may assign or sell 
5    subscriptions to another person within the same utility 
6    service territory.
7        Through the development of its long-term renewable 
8    resources procurement plan, the Agency may consider 
9    whether community renewable generation projects utilizing 
10    technologies other than photovoltaics should be supported 
11    through State-administered incentive funding, and may 
12    issue requests for information to gauge market demand. 
13        Electric utilities shall provide a monetary credit to 
14    a subscriber's subsequent bill for service for the 
15    proportional output of a community renewable generation 
16    project attributable to that subscriber as specified in 
17    Section 16-107.5 of the Public Utilities Act.
18        The Agency shall purchase renewable energy credits 
19    from subscribed shares of photovoltaic community renewable 
20    generation projects through the Adjustable Block program 
21    described in subparagraph (K) of this paragraph (1) or 
22    through the Illinois Solar for All Program described in 
23    Section 1-56 of this Act. The electric utility shall 
24    purchase any unsubscribed energy from community renewable 
25    generation projects that are Qualifying Facilities ("QF") 
26    under the electric utility's tariff for purchasing the 
 
 
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1    output from QFs under Public Utilities Regulatory Policies 
2    Act of 1978. 
3        The owners of and any subscribers to a community 
4    renewable generation project shall not be considered 
5    public utilities or alternative retail electricity 
6    suppliers under the Public Utilities Act solely as a 
7    result of their interest in or subscription to a community 
8    renewable generation project and shall not be required to 
9    become an alternative retail electric supplier by 
10    participating in a community renewable generation project 
11    with a public utility.
12        (O) For the delivery year beginning June 1, 2018, the 
13    long-term renewable resources procurement plan required by 
14    this subsection (c) shall provide for the Agency to 
15    procure contracts to continue offering the Illinois Solar 
16    for All Program described in subsection (b) of Section 
17    1-56 of this Act, and the contracts approved by the 
18    Commission shall be executed by the utilities that are 
19    subject to this subsection (c). The long-term renewable 
20    resources procurement plan shall allocate up to 
21    $50,000,000 per delivery year to fund the programs, and 
22    the plan shall determine the amount of funding to be 
23    apportioned to the programs identified in subsection (b) 
24    of Section 1-56 of this Act; provided that for the 
25    delivery years beginning June 1, 2021, June 1, 2022, and 
26    June 1, 2023, the long-term renewable resources 
 
 
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1    procurement plan may average the annual budgets over a 
2    3-year period to account for program ramp-up. For the 
3    delivery years beginning June 1, 2021, June 1, 2024, June 
4    1, 2027, and June 1, 2030 and additional $10,000,000 shall 
5    be provided to the Department of Commerce and Economic 
6    Opportunity to implement the workforce development 
7    programs and reporting as outlined in Section 16-108.12 of 
8    the Public Utilities Act. In making the determinations 
9    required under this subparagraph (O), the Commission shall 
10    consider the experience and performance under the programs 
11    and any evaluation reports. The Commission shall also 
12    provide for an independent evaluation of those programs on 
13    a periodic basis that are funded under this subparagraph 
14    (O).
15        (P) All programs and procurements under this 
16    subsection (c) shall be designed to encourage 
17    participating projects to use a diverse and equitable 
18    workforce and a diverse set of contractors, including 
19    minority-owned businesses, disadvantaged businesses, 
20    trade unions, graduates of any workforce training programs 
21    administered under this Act, and small businesses.
22        The Agency shall develop a method to optimize 
23    procurement of renewable energy credits from proposed 
24    utility-scale projects that are located in communities 
25    eligible to receive Energy Transition Community Grants 
26    pursuant to Section 10-20 of the Energy Community 
 
 
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1    Reinvestment Act. If this requirement conflicts with other 
2    provisions of law or the Agency determines that full 
3    compliance with the requirements of this subparagraph (P) 
4    would be unreasonably costly or administratively 
5    impractical, the Agency is to propose alternative 
6    approaches to achieve development of renewable energy 
7    resources in communities eligible to receive Energy 
8    Transition Community Grants pursuant to Section 10-20 of 
9    the Energy Community Reinvestment Act or seek an exemption 
10    from this requirement from the Commission. 
11        (Q) Each facility listed in subitems (i) through (ix) 
12    of item (1) of this subparagraph (Q) for which a renewable 
13    energy credit delivery contract is signed after the 
14    effective date of this amendatory Act of the 102nd General 
15    Assembly is subject to the following requirements through 
16    the Agency's long-term renewable resources procurement 
17    plan:
18            (1) Each facility shall be subject to the 
19        prevailing wage requirements included in the 
20        Prevailing Wage Act. The Agency shall require 
21        verification that all construction performed on the 
22        facility by the renewable energy credit delivery 
23        contract holder, its contractors, or its 
24        subcontractors relating to construction of the 
25        facility is performed by construction employees 
26        receiving an amount for that work equal to or greater 
 
 
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1        than the general prevailing rate, as that term is 
2        defined in Section 2 3 of the Prevailing Wage Act. For 
3        purposes of this item (1), "house of worship" means 
4        property that is both (1) used exclusively by a 
5        religious society or body of persons as a place for 
6        religious exercise or religious worship and (2) 
7        recognized as exempt from taxation pursuant to Section 
8        15-40 of the Property Tax Code. This item (1) shall 
9        apply to any the following: 
10                (i) all new utility-scale wind projects;
11                (ii) all new utility-scale photovoltaic 
12            projects and repowered wind projects;
13                (iii) all new brownfield photovoltaic 
14            projects;
15                (iv) all new photovoltaic community renewable 
16            energy facilities that qualify for item (iii) of 
17            subparagraph (K) of this paragraph (1);
18                (v) all new community driven community 
19            photovoltaic projects that qualify for item (v) of 
20            subparagraph (K) of this paragraph (1);
21                (vi) all new photovoltaic projects on public 
22            school land that qualify for item (iv) of 
23            subparagraph (K) of this paragraph (1);
24                (vii) all new photovoltaic distributed 
25            renewable energy generation devices that (1) 
26            qualify for item (i) of subparagraph (K) of this 
 
 
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1            paragraph (1); (2) are not projects that serve 
2            single-family or multi-family residential 
3            buildings; and (3) are not houses of worship where 
4            the aggregate capacity including colocated    
5            collocated projects would not exceed 100 
6            kilowatts;
7                (viii) all new photovoltaic distributed 
8            renewable energy generation devices that (1) 
9            qualify for item (ii) of subparagraph (K) of this 
10            paragraph (1); (2) are not projects that serve 
11            single-family or multi-family residential 
12            buildings; and (3) are not houses of worship where 
13            the aggregate capacity including colocated    
14            collocated projects would not exceed 100 
15            kilowatts;
16                (ix) all new, modernized, or retooled 
17            hydropower facilities. 
18            (2) Renewable energy credits procured from new 
19        utility-scale wind projects, new utility-scale solar 
20        projects, new brownfield solar projects, repowered 
21        wind projects, and retooled hydropower facilities 
22        pursuant to Agency procurement events occurring after 
23        the effective date of this amendatory Act of the 102nd 
24        General Assembly must be from facilities built by 
25        general contractors that must enter into a project 
26        labor agreement, as defined by this Act, prior to 
 
 
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1        construction. The project labor agreement shall be 
2        filed with the Director in accordance with procedures 
3        established by the Agency through its long-term 
4        renewable resources procurement plan. Any information 
5        submitted to the Agency in this item (2) shall be 
6        considered commercially sensitive information. At a 
7        minimum, the project labor agreement must provide the 
8        names, addresses, and occupations of the owner of the 
9        plant and the individuals representing the labor 
10        organization employees participating in the project 
11        labor agreement consistent with the Project Labor 
12        Agreements Act. The agreement must also specify the 
13        terms and conditions as defined by this Act.
14            (2.5) Energy storage credits procured from battery 
15        storage projects pursuant to Agency procurement events 
16        and additional energy storage resources procured in 
17        accordance with subparagraph (B) of paragraph (3) of 
18        subsection (d-20) of this Section pursuant to Agency 
19        procurement events occurring after the effective date 
20        of this amendatory Act of the 104th General Assembly 
21        must be from facilities built by general contractors 
22        that must enter into a project labor agreement prior 
23        to construction. The project labor agreement shall be 
24        filed with the Director in accordance with procedures 
25        established by the Agency through its long-term 
26        renewable resources procurement plan. Any information 
 
 
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1        submitted to the Agency pursuant to this item (2.5) 
2        shall be considered commercially sensitive 
3        information. At a minimum, the project labor agreement 
4        must provide the names, addresses, and occupations of 
5        the owner of the plant and the individuals 
6        representing the labor organization employees 
7        participating in the project labor agreement 
8        consistent with the Project Labor Agreements Act. The 
9        agreement must also specify the terms and conditions, 
10        as defined by this Act.    
11            (3) It is the intent of this Section to ensure that 
12        economic development occurs across Illinois 
13        communities, that emerging businesses may grow, and 
14        that there is improved access to the clean energy 
15        economy by persons who have greater economic burdens 
16        to success. The Agency shall take into consideration 
17        the unique cost of compliance of this subparagraph (Q) 
18        that might be borne by equity eligible contractors, 
19        shall include such costs when determining the price of 
20        renewable energy credits in the Adjustable Block 
21        program, and shall take such costs into consideration 
22        in a nondiscriminatory manner when comparing bids for 
23        competitive procurements. The Agency shall consider 
24        costs associated with compliance whether in the 
25        development, financing, or construction of projects. 
26        The Agency shall periodically review the assumptions 
 
 
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1        in these costs and may adjust prices, in compliance 
2        with subparagraph (M) of this paragraph (1).
3        (R) In its long-term renewable resources procurement 
4    plan, the Agency shall establish a self-direct renewable 
5    portfolio standard compliance program for eligible 
6    self-direct customers that purchase renewable energy 
7    credits from utility-scale wind and solar projects through 
8    long-term agreements for purchase of renewable energy 
9    credits as described in this Section. Such long-term 
10    agreements may include the purchase of energy or other 
11    products on a physical or financial basis and may involve 
12    an alternative retail electric supplier as defined in 
13    Section 16-102 of the Public Utilities Act. This program 
14    shall take effect in the delivery year commencing June 1, 
15    2023.
16            (1) For the purposes of this subparagraph:
17            "Eligible self-direct customer" means any retail 
18        customers of an electric utility that serves 3,000,000 
19        or more retail customers in the State and whose total 
20        highest 30-minute demand was more than 10,000 
21        kilowatts, or any retail customers of an electric 
22        utility that serves less than 3,000,000 retail 
23        customers but more than 500,000 retail customers in 
24        the State and whose total highest 15-minute demand was 
25        more than 10,000 kilowatts.
26            "Retail customer" has the meaning set forth in 
 
 
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1        Section 16-102 of the Public Utilities Act and 
2        multiple retail customer accounts under the same 
3        corporate parent may aggregate their account demands 
4        to meet the 10,000 kilowatt threshold. The criteria 
5        for determining whether this subparagraph is 
6        applicable to a retail customer shall be based on the 
7        12 consecutive billing periods prior to the start of 
8        the year in which the application is filed.
9            (2) For renewable energy credits to count toward 
10        the self-direct renewable portfolio standard 
11        compliance program, they must:
12                (i) qualify as renewable energy credits as 
13            defined in Section 1-10 of this Act;
14                (ii) be sourced from one or more renewable 
15            energy generating facilities that comply with the 
16            geographic requirements as set forth in 
17            subparagraph (I) of paragraph (1) of subsection 
18            (c) as interpreted through the Agency's long-term 
19            renewable resources procurement plan, or, where 
20            applicable, the geographic requirements that 
21            governed utility-scale renewable energy credits at 
22            the time the eligible self-direct customer entered 
23            into the applicable renewable energy credit 
24            purchase agreement;
25                (iii) be procured through long-term contracts 
26            with term lengths of at least 10 years either 
 
 
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1            directly with the renewable energy generating 
2            facility or through a bundled power purchase 
3            agreement, a virtual power purchase agreement, an 
4            agreement between the renewable generating 
5            facility, an alternative retail electric supplier, 
6            and the customer, or such other structure as is 
7            permissible under this subparagraph (R);
8                (iv) be equivalent in volume to at least 40% 
9            of the eligible self-direct customer's usage, 
10            determined annually by the eligible self-direct 
11            customer's usage during the previous delivery 
12            year, measured to the nearest megawatt-hour;
13                (v) be retired by or on behalf of the large 
14            energy customer;
15                (vi) be sourced from new utility-scale wind 
16            projects or new utility-scale solar projects; and
17                (vii) if the contracts for renewable energy 
18            credits are entered into after the effective date 
19            of this amendatory Act of the 102nd General 
20            Assembly, the new utility-scale wind projects or 
21            new utility-scale solar projects must comply with 
22            the requirements established in subparagraphs (P) 
23            and (Q) of paragraph (1) of this subsection (c) 
24            and subsection (c-10).
25            (3) The self-direct renewable portfolio standard 
26        compliance program shall be designed to allow eligible 
 
 
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1        self-direct customers to procure new renewable energy 
2        credits from new utility-scale wind projects or new 
3        utility-scale photovoltaic projects. The Agency shall 
4        annually determine the amount of utility-scale 
5        renewable energy credits it will include each year 
6        from the self-direct renewable portfolio standard 
7        compliance program, subject to receiving qualifying 
8        applications. In making this determination, the Agency 
9        shall evaluate publicly available analyses and studies 
10        of the potential market size for utility-scale 
11        renewable energy long-term purchase agreements by 
12        commercial and industrial energy customers and make 
13        that report publicly available. If demand for 
14        participation in the self-direct renewable portfolio 
15        standard compliance program exceeds availability, the 
16        Agency shall ensure participation is evenly split 
17        between commercial and industrial users to the extent 
18        there is sufficient demand from both customer classes. 
19        Each renewable energy credit procured pursuant to this 
20        subparagraph (R) by a self-direct customer shall 
21        reduce the total volume of renewable energy credits 
22        the Agency is otherwise required to procure from new 
23        utility-scale projects pursuant to subparagraph (C) of 
24        paragraph (1) of this subsection (c) on behalf of 
25        contracting utilities where the eligible self-direct 
26        customer is located. The self-direct customer shall 
 
 
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1        file an annual compliance report with the Agency 
2        pursuant to terms established by the Agency through 
3        its long-term renewable resources procurement plan to 
4        be eligible for participation in this program. 
5        Customers must provide the Agency with their most 
6        recent electricity billing statements or other 
7        information deemed necessary by the Agency to 
8        demonstrate they are an eligible self-direct customer.
9            (4) The Commission shall approve a reduction in 
10        the volumetric charges collected pursuant to Section 
11        16-108 of the Public Utilities Act for approved 
12        eligible self-direct customers equivalent to the 
13        anticipated cost of renewable energy credit deliveries 
14        under contracts for new utility-scale wind and new 
15        utility-scale solar entered for each delivery year 
16        after the large energy customer begins retiring 
17        eligible new utility-scale utility scale renewable 
18        energy credits for self-compliance. The self-direct 
19        credit amount shall be determined annually and is 
20        equal to the estimated portion of the cost authorized 
21        by subparagraph (E) of paragraph (1) of this 
22        subsection (c) that supported the annual procurement 
23        of utility-scale renewable energy credits in the prior 
24        delivery year using a methodology described in the 
25        long-term renewable resources procurement plan, 
26        expressed on a per kilowatthour basis, and does not 
 
 
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1        include (i) costs associated with any contracts 
2        entered into before the delivery year in which the 
3        customer files the initial compliance report to be 
4        eligible for participation in the self-direct program, 
5        and (ii) costs associated with procuring renewable 
6        energy credits through existing and future contracts 
7        through the Adjustable Block Program, subsection (c-5) 
8        of this Section 1-75, and the Solar for All Program. 
9        The Agency shall assist the Commission in determining 
10        the current and future costs. The Agency must 
11        determine the self-direct credit amount for new and 
12        existing eligible self-direct customers and submit 
13        this to the Commission in an annual compliance filing. 
14        The Commission must approve the self-direct credit 
15        amount by June 1, 2023 and June 1 of each delivery year 
16        thereafter.
17            (5) Customers described in this subparagraph (R) 
18        shall apply, on a form developed by the Agency, to the 
19        Agency to be designated as a self-direct eligible 
20        customer. Once the Agency determines that a 
21        self-direct customer is eligible for participation in 
22        the program, the self-direct customer will remain 
23        eligible until the end of the term of the contract. 
24        Thereafter, application may be made not less than 12 
25        months before the filing date of the long-term 
26        renewable resources procurement plan described in this 
 
 
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1        Act. At a minimum, such application shall contain the 
2        following:
3                (i) the customer's certification that, at the 
4            time of the customer's application, the customer 
5            qualifies to be a self-direct eligible customer, 
6            including documents demonstrating that 
7            qualification;
8                (ii) the customer's certification that the 
9            customer has entered into or will enter into by 
10            the beginning of the applicable procurement year, 
11            one or more bilateral contracts for new wind 
12            projects or new photovoltaic projects, including 
13            supporting documentation;
14                (iii) certification that the contract or 
15            contracts for new renewable energy resources are 
16            long-term contracts with term lengths of at least 
17            10 years, including supporting documentation;
18                (iv) certification of the quantities of 
19            renewable energy credits that the customer will 
20            purchase each year under such contract or 
21            contracts, including supporting documentation;
22                (v) proof that the contract is sufficient to 
23            produce renewable energy credits to be equivalent 
24            in volume to at least 40% of the large energy 
25            customer's usage from the previous delivery year, 
26            measured to the nearest megawatt-hour; and
 
 
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1                (vi) certification that the customer intends 
2            to maintain the contract for the duration of the 
3            length of the contract.
4            (6) If a customer receives the self-direct credit 
5        but fails to properly procure and retire renewable 
6        energy credits as required under this subparagraph 
7        (R), the Commission, on petition from the Agency and 
8        after notice and hearing, may direct such customer's 
9        utility to recover the cost of the wrongfully received 
10        self-direct credits plus interest through an adder to 
11        charges assessed pursuant to Section 16-108 of the 
12        Public Utilities Act. Self-direct customers who 
13        knowingly fail to properly procure and retire 
14        renewable energy credits and do not notify the Agency 
15        are ineligible for continued participation in the 
16        self-direct renewable portfolio standard compliance 
17        program.
18        (2) (Blank).
19        (3) (Blank). 
20        (4) The electric utility shall retire all renewable 
21    energy credits used to comply with the standard.
22        (5) Beginning with the 2010 delivery year and ending 
23    June 1, 2017, an electric utility subject to this 
24    subsection (c) shall apply the lesser of the maximum 
25    alternative compliance payment rate or the most recent 
26    estimated alternative compliance payment rate for its 
 
 
10400SB0025ham002- 255 -LRB104 07069 AAS 28576 a

1    service territory for the corresponding compliance period, 
2    established pursuant to subsection (d) of Section 16-115D 
3    of the Public Utilities Act to its retail customers that 
4    take service pursuant to the electric utility's hourly 
5    pricing tariff or tariffs. The electric utility shall 
6    retain all amounts collected as a result of the 
7    application of the alternative compliance payment rate or 
8    rates to such customers, and, beginning in 2011, the 
9    utility shall include in the information provided under 
10    item (1) of subsection (d) of Section 16-111.5 of the 
11    Public Utilities Act the amounts collected under the 
12    alternative compliance payment rate or rates for the prior 
13    year ending May 31. Notwithstanding any limitation on the 
14    procurement of renewable energy resources imposed by item 
15    (2) of this subsection (c), the Agency shall increase its 
16    spending on the purchase of renewable energy resources to 
17    be procured by the electric utility for the next plan year 
18    by an amount equal to the amounts collected by the utility 
19    under the alternative compliance payment rate or rates in 
20    the prior year ending May 31.
21        (6) The electric utility shall be entitled to recover 
22    all of its costs associated with the procurement of 
23    renewable energy credits under plans approved under this 
24    Section and Section 16-111.5 of the Public Utilities Act. 
25    These costs shall include associated reasonable expenses 
26    for implementing the procurement programs, including, but 
 
 
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1    not limited to, the costs of administering and evaluating 
2    the Adjustable Block program, through an automatic 
3    adjustment clause tariff in accordance with subsection (k) 
4    of Section 16-108 of the Public Utilities Act.
5        (7) Renewable energy credits procured from new 
6    photovoltaic projects or new distributed renewable energy 
7    generation devices under this Section after June 1, 2017 
8    (the effective date of Public Act 99-906) must be procured 
9    from devices installed by a qualified person in compliance 
10    with the requirements of Section 16-128A of the Public 
11    Utilities Act and any rules or regulations adopted 
12    thereunder.
13        In meeting the renewable energy requirements of this 
14    subsection (c), to the extent feasible and consistent with 
15    State and federal law, the renewable energy credit 
16    procurements, Adjustable Block solar program, and 
17    community renewable generation program shall provide 
18    employment opportunities for all segments of the 
19    population and workforce, including minority-owned and 
20    female-owned business enterprises, and shall not, 
21    consistent with State and federal law, discriminate based 
22    on race or socioeconomic status. 
23    (c-5) Procurement of renewable energy credits from new 
24renewable energy facilities installed at or adjacent to the 
25sites of electric generating facilities that burn or burned 
26coal as their primary fuel source.
 
 
10400SB0025ham002- 257 -LRB104 07069 AAS 28576 a

1        (1) In addition to the procurement of renewable energy 
2    credits pursuant to long-term renewable resources 
3    procurement plans in accordance with subsection (c) of 
4    this Section and Section 16-111.5 of the Public Utilities 
5    Act, the Agency shall conduct procurement events in 
6    accordance with this subsection (c-5) for the procurement 
7    by electric utilities that served more than 300,000 retail 
8    customers in this State as of January 1, 2019 of renewable 
9    energy credits from new renewable energy facilities to be 
10    installed at or adjacent to the sites of electric 
11    generating facilities that, as of January 1, 2016, burned 
12    coal as their primary fuel source and meet the other 
13    criteria specified in this subsection (c-5). For purposes 
14    of this subsection (c-5), "new renewable energy facility" 
15    means a new utility-scale solar project as defined in this 
16    Section 1-75. The renewable energy credits procured 
17    pursuant to this subsection (c-5) may be included or 
18    counted for purposes of compliance with the amounts of 
19    renewable energy credits required to be procured pursuant 
20    to subsection (c) of this Section to the extent that there 
21    are otherwise shortfalls in compliance with such 
22    requirements. The procurement of renewable energy credits 
23    by electric utilities pursuant to this subsection (c-5) 
24    shall be funded solely by revenues collected from the Coal 
25    to Solar and Energy Storage Initiative Charge provided for 
26    in this subsection (c-5) and subsection (i-5) of Section 
 
 
10400SB0025ham002- 258 -LRB104 07069 AAS 28576 a

1    16-108 of the Public Utilities Act, shall not be funded by 
2    revenues collected through any of the other funding 
3    mechanisms provided for in subsection (c) of this Section, 
4    and shall not be subject to the limitation imposed by 
5    subsection (c) on charges to retail customers for costs to 
6    procure renewable energy resources pursuant to subsection 
7    (c), and shall not be subject to any other requirements or 
8    limitations of subsection (c).
9        (2) The Agency shall conduct 2 procurement events to 
10    select owners of electric generating facilities meeting 
11    the eligibility criteria specified in this subsection 
12    (c-5) to enter into long-term contracts to sell renewable 
13    energy credits to electric utilities serving more than 
14    300,000 retail customers in this State as of January 1, 
15    2019. The first procurement event shall be conducted no 
16    later than March 31, 2022, unless the Agency elects to 
17    delay it, until no later than May 1, 2022, due to its 
18    overall volume of work, and shall be to select owners of 
19    electric generating facilities located in this State and 
20    south of federal Interstate Highway 80 that meet the 
21    eligibility criteria specified in this subsection (c-5). 
22    The second procurement event shall be conducted no sooner 
23    than September 30, 2022 and no later than October 31, 2022 
24    and shall be to select owners of electric generating 
25    facilities located anywhere in this State that meet the 
26    eligibility criteria specified in this subsection (c-5). 
 
 
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1    The Agency shall establish and announce a time period, 
2    which shall begin no later than 30 days prior to the 
3    scheduled date for the procurement event, during which 
4    applicants may submit applications to be selected as 
5    suppliers of renewable energy credits pursuant to this 
6    subsection (c-5). The eligibility criteria for selection 
7    as a supplier of renewable energy credits pursuant to this 
8    subsection (c-5) shall be as follows:
9            (A) The applicant owns an electric generating 
10        facility located in this State that: (i) as of January 
11        1, 2016, burned coal as its primary fuel to generate 
12        electricity; and (ii) has, or had prior to retirement, 
13        an electric generating capacity of at least 150 
14        megawatts. The electric generating facility can be 
15        either: (i) retired as of the date of the procurement 
16        event; or (ii) still operating as of the date of the 
17        procurement event.
18            (B) The applicant is not (i) an electric 
19        cooperative as defined in Section 3-119 of the Public 
20        Utilities Act, or (ii) an entity described in 
21        subsection (b)(1) of Section 3-105 of the Public 
22        Utilities Act, or an association or consortium of or 
23        an entity owned by entities described in (i) or (ii); 
24        and the coal-fueled electric generating facility was 
25        at one time owned, in whole or in part, by a public 
26        utility as defined in Section 3-105 of the Public 
 
 
10400SB0025ham002- 260 -LRB104 07069 AAS 28576 a

1        Utilities Act.
2            (C) If participating in the first procurement 
3        event, the applicant proposes and commits to construct 
4        and operate, at the site, and if necessary for 
5        sufficient space on property adjacent to the existing 
6        property, at which the electric generating facility 
7        identified in paragraph (A) is located: (i) a new 
8        renewable energy facility of at least 20 megawatts but 
9        no more than 100 megawatts of electric generating 
10        capacity, and (ii) an energy storage facility having a 
11        storage capacity equal to at least 2 megawatts and at 
12        most 10 megawatts. If participating in the second 
13        procurement event, the applicant proposes and commits 
14        to construct and operate, at the site, and if 
15        necessary for sufficient space on property adjacent to 
16        the existing property, at which the electric 
17        generating facility identified in paragraph (A) is 
18        located: (i) a new renewable energy facility of at 
19        least 5 megawatts but no more than 20 megawatts of 
20        electric generating capacity, and (ii) an energy 
21        storage facility having a storage capacity equal to at 
22        least 0.5 megawatts and at most one megawatt.
23            (D) The applicant agrees that the new renewable 
24        energy facility and the energy storage facility will 
25        be constructed or installed by a qualified entity or 
26        entities in compliance with the requirements of 
 
 
10400SB0025ham002- 261 -LRB104 07069 AAS 28576 a

1        subsection (g) of Section 16-128A of the Public 
2        Utilities Act and any rules adopted thereunder.
3            (E) The applicant agrees that personnel operating 
4        the new renewable energy facility and the energy 
5        storage facility will have the requisite skills, 
6        knowledge, training, experience, and competence, which 
7        may be demonstrated by completion or current 
8        participation and ultimate completion by employees of 
9        an accredited or otherwise recognized apprenticeship 
10        program for the employee's particular craft, trade, or 
11        skill, including through training and education 
12        courses and opportunities offered by the owner to 
13        employees of the coal-fueled electric generating 
14        facility or by previous employment experience 
15        performing the employee's particular work skill or 
16        function.
17            (F) The applicant commits that not less than the 
18        prevailing wage, as determined pursuant to the 
19        Prevailing Wage Act, will be paid to the applicant's 
20        employees engaged in construction activities 
21        associated with the new renewable energy facility and 
22        the new energy storage facility and to the employees 
23        of applicant's contractors engaged in construction 
24        activities associated with the new renewable energy 
25        facility and the new energy storage facility, and 
26        that, on or before the commercial operation date of 
 
 
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1        the new renewable energy facility, the applicant shall 
2        file a report with the Agency certifying that the 
3        requirements of this subparagraph (F) have been met.
4            (G) The applicant commits that if selected, it 
5        will negotiate a project labor agreement for the 
6        construction of the new renewable energy facility and 
7        associated energy storage facility that includes 
8        provisions requiring the parties to the agreement to 
9        work together to establish diversity threshold 
10        requirements and to ensure best efforts to meet 
11        diversity targets, improve diversity at the applicable 
12        job site, create diverse apprenticeship opportunities, 
13        and create opportunities to employ former coal-fired 
14        power plant workers.
15            (H) The applicant commits to enter into a contract 
16        or contracts for the applicable duration to provide 
17        specified numbers of renewable energy credits each 
18        year from the new renewable energy facility to 
19        electric utilities that served more than 300,000 
20        retail customers in this State as of January 1, 2019, 
21        at a price of $30 per renewable energy credit. The 
22        price per renewable energy credit shall be fixed at 
23        $30 for the applicable duration and the renewable 
24        energy credits shall not be indexed renewable energy 
25        credits as provided for in item (v) of subparagraph 
26        (G) of paragraph (1) of subsection (c) of Section 1-75 
 
 
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1        of this Act. The applicable duration of each contract 
2        shall be 20 years, unless the applicant is physically 
3        interconnected to the PJM Interconnection, LLC 
4        transmission grid and had a generating capacity of at 
5        least 1,200 megawatts as of January 1, 2021, in which 
6        case the applicable duration of the contract shall be 
7        15 years.
8            (I) The applicant's application is certified by an 
9        officer of the applicant and by an officer of the 
10        applicant's ultimate parent company, if any.
11        (3) An applicant may submit applications to contract 
12    to supply renewable energy credits from more than one new 
13    renewable energy facility to be constructed at or adjacent 
14    to one or more qualifying electric generating facilities 
15    owned by the applicant. The Agency may select new 
16    renewable energy facilities to be located at or adjacent 
17    to the sites of more than one qualifying electric 
18    generation facility owned by an applicant to contract with 
19    electric utilities to supply renewable energy credits from 
20    such facilities.
21        (4) The Agency shall assess fees to each applicant to 
22    recover the Agency's costs incurred in receiving and 
23    evaluating applications, conducting the procurement event, 
24    developing contracts for sale, delivery and purchase of 
25    renewable energy credits, and monitoring the 
26    administration of such contracts, as provided for in this 
 
 
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1    subsection (c-5), including fees paid to a procurement 
2    administrator retained by the Agency for one or more of 
3    these purposes.
4        (5) The Agency shall select the applicants and the new 
5    renewable energy facilities to contract with electric 
6    utilities to supply renewable energy credits in accordance 
7    with this subsection (c-5). In the first procurement 
8    event, the Agency shall select applicants and new 
9    renewable energy facilities to supply renewable energy 
10    credits, at a price of $30 per renewable energy credit, 
11    aggregating to no less than 400,000 renewable energy 
12    credits per year for the applicable duration, assuming 
13    sufficient qualifying applications to supply, in the 
14    aggregate, at least that amount of renewable energy 
15    credits per year; and not more than 580,000 renewable 
16    energy credits per year for the applicable duration. In 
17    the second procurement event, the Agency shall select 
18    applicants and new renewable energy facilities to supply 
19    renewable energy credits, at a price of $30 per renewable 
20    energy credit, aggregating to no more than 625,000 
21    renewable energy credits per year less the amount of 
22    renewable energy credits each year contracted for as a 
23    result of the first procurement event, for the applicable 
24    durations. The number of renewable energy credits to be 
25    procured as specified in this paragraph (5) shall not be 
26    reduced based on renewable energy credits procured in the 
 
 
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1    self-direct renewable energy credit compliance program 
2    established pursuant to subparagraph (R) of paragraph (1) 
3    of subsection (c) of Section 1-75.
4        (6) The obligation to purchase renewable energy 
5    credits from the applicants and their new renewable energy 
6    facilities selected by the Agency shall be allocated to 
7    the electric utilities based on their respective 
8    percentages of kilowatthours delivered to delivery 
9    services customers to the aggregate kilowatthour 
10    deliveries by the electric utilities to delivery services 
11    customers for the year ended December 31, 2021. In order 
12    to achieve these allocation percentages between or among 
13    the electric utilities, the Agency shall require each 
14    applicant that is selected in the procurement event to 
15    enter into a contract with each electric utility for the 
16    sale and purchase of renewable energy credits from each 
17    new renewable energy facility to be constructed and 
18    operated by the applicant, with the sale and purchase 
19    obligations under the contracts to aggregate to the total 
20    number of renewable energy credits per year to be supplied 
21    by the applicant from the new renewable energy facility.
22        (7) The Agency shall submit its proposed selection of 
23    applicants, new renewable energy facilities to be 
24    constructed, and renewable energy credit amounts for each 
25    procurement event to the Commission for approval. The 
26    Commission shall, within 2 business days after receipt of 
 
 
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1    the Agency's proposed selections, approve the proposed 
2    selections if it determines that the applicants and the 
3    new renewable energy facilities to be constructed meet the 
4    selection criteria set forth in this subsection (c-5) and 
5    that the Agency seeks approval for contracts of applicable 
6    durations aggregating to no more than the maximum amount 
7    of renewable energy credits per year authorized by this 
8    subsection (c-5) for the procurement event, at a price of 
9    $30 per renewable energy credit.
10        (8) The Agency, in conjunction with its procurement 
11    administrator if one is retained, the electric utilities, 
12    and potential applicants for contracts to produce and 
13    supply renewable energy credits pursuant to this 
14    subsection (c-5), shall develop a standard form contract 
15    for the sale, delivery and purchase of renewable energy 
16    credits pursuant to this subsection (c-5). Each contract 
17    resulting from the first procurement event shall allow for 
18    a commercial operation date for the new renewable energy 
19    facility of either June 1, 2023 or June 1, 2024, with such 
20    dates subject to adjustment as provided in this paragraph. 
21    Each contract resulting from the second procurement event 
22    shall provide for a commercial operation date on June 1 
23    next occurring up to 48 months after execution of the 
24    contract. Each contract shall provide that the owner shall 
25    receive payments for renewable energy credits for the 
26    applicable durations beginning with the commercial 
 
 
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1    operation date of the new renewable energy facility. The 
2    form contract shall provide for adjustments to the 
3    commercial operation and payment start dates as needed due 
4    to any delays in completing the procurement and 
5    contracting processes, in finalizing interconnection 
6    agreements and installing interconnection facilities, and 
7    in obtaining other necessary governmental permits and 
8    approvals. The form contract shall be, to the maximum 
9    extent possible, consistent with standard electric 
10    industry contracts for sale, delivery, and purchase of 
11    renewable energy credits while taking into account the 
12    specific requirements of this subsection (c-5). The form 
13    contract shall provide for over-delivery and 
14    under-delivery of renewable energy credits within 
15    reasonable ranges during each 12-month period and penalty, 
16    default, and enforcement provisions for failure of the 
17    selling party to deliver renewable energy credits as 
18    specified in the contract and to comply with the 
19    requirements of this subsection (c-5). The standard form 
20    contract shall specify that all renewable energy credits 
21    delivered to the electric utility pursuant to the contract 
22    shall be retired. The Agency shall make the proposed 
23    contracts available for a reasonable period for comment by 
24    potential applicants, and shall publish the final form 
25    contract at least 30 days before the date of the first 
26    procurement event.
 
 
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1        (9) Coal to Solar and Energy Storage Initiative 
2    Charge.
3            (A) By no later than July 1, 2022, each electric 
4        utility that served more than 300,000 retail customers 
5        in this State as of January 1, 2019 shall file a tariff 
6        with the Commission for the billing and collection of 
7        a Coal to Solar and Energy Storage Initiative Charge 
8        in accordance with subsection (i-5) of Section 16-108 
9        of the Public Utilities Act, with such tariff to be 
10        effective, following review and approval or 
11        modification by the Commission, beginning January 1, 
12        2023. The tariff shall provide for the calculation and 
13        setting of the electric utility's Coal to Solar and 
14        Energy Storage Initiative Charge to collect revenues 
15        estimated to be sufficient, in the aggregate, (i) to 
16        enable the electric utility to pay for the renewable 
17        energy credits it has contracted to purchase in the 
18        delivery year beginning June 1, 2023 and each delivery 
19        year thereafter from new renewable energy facilities 
20        located at the sites of qualifying electric generating 
21        facilities, and (ii) to fund the grant payments to be 
22        made in each delivery year by the Department of 
23        Commerce and Economic Opportunity, or any successor 
24        department or agency, which shall be referred to in 
25        this subsection (c-5) as the Department, pursuant to 
26        paragraph (10) of this subsection (c-5). The electric 
 
 
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1        utility's tariff shall provide for the billing and 
2        collection of the Coal to Solar and Energy Storage 
3        Initiative Charge on each kilowatthour of electricity 
4        delivered to its delivery services customers within 
5        its service territory and shall provide for an annual 
6        reconciliation of revenues collected with actual 
7        costs, in accordance with subsection (i-5) of Section 
8        16-108 of the Public Utilities Act.
9            (B) Each electric utility shall remit on a monthly 
10        basis to the State Treasurer, for deposit in the Coal 
11        to Solar and Energy Storage Initiative Fund provided 
12        for in this subsection (c-5), the electric utility's 
13        collections of the Coal to Solar and Energy Storage 
14        Initiative Charge in the amount estimated to be needed 
15        by the Department for grant payments pursuant to grant 
16        contracts entered into by the Department pursuant to 
17        paragraph (10) of this subsection (c-5).
18        (10) Coal to Solar and Energy Storage Initiative Fund.
19            (A) The Coal to Solar and Energy Storage 
20        Initiative Fund is established as a special fund in 
21        the State treasury. The Coal to Solar and Energy 
22        Storage Initiative Fund is authorized to receive, by 
23        statutory deposit, that portion specified in item (B) 
24        of paragraph (9) of this subsection (c-5) of moneys 
25        collected by electric utilities through imposition of 
26        the Coal to Solar and Energy Storage Initiative Charge 
 
 
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1        required by this subsection (c-5). The Coal to Solar 
2        and Energy Storage Initiative Fund shall be 
3        administered by the Department to provide grants to 
4        support the installation and operation of energy 
5        storage facilities at the sites of qualifying electric 
6        generating facilities meeting the criteria specified 
7        in this paragraph (10).
8            (B) The Coal to Solar and Energy Storage 
9        Initiative Fund shall not be subject to sweeps, 
10        administrative charges, or chargebacks, including, but 
11        not limited to, those authorized under Section 8h of 
12        the State Finance Act, that would in any way result in 
13        the transfer of those funds from the Coal to Solar and 
14        Energy Storage Initiative Fund to any other fund of 
15        this State or in having any such funds utilized for any 
16        purpose other than the express purposes set forth in 
17        this paragraph (10).
18            (C) The Department shall utilize up to 
19        $280,500,000 in the Coal to Solar and Energy Storage 
20        Initiative Fund for grants, assuming sufficient 
21        qualifying applicants, to support installation of 
22        energy storage facilities at the sites of up to 3 
23        qualifying electric generating facilities located in 
24        the Midcontinent Independent System Operator, Inc., 
25        region in Illinois and the sites of up to 2 qualifying 
26        electric generating facilities located in the PJM 
 
 
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1        Interconnection, LLC region in Illinois that meet the 
2        criteria set forth in this subparagraph (C). The 
3        criteria for receipt of a grant pursuant to this 
4        subparagraph (C) are as follows:
5                (1) the electric generating facility at the 
6            site has, or had prior to retirement, an electric 
7            generating capacity of at least 150 megawatts;
8                (2) the electric generating facility burns (or 
9            burned prior to retirement) coal as its primary 
10            source of fuel;
11                (3) if the electric generating facility is 
12            retired, it was retired subsequent to January 1, 
13            2016;
14                (4) the owner of the electric generating 
15            facility has not been selected by the Agency 
16            pursuant to this subsection (c-5) of this Section 
17            to enter into a contract to sell renewable energy 
18            credits to one or more electric utilities from a 
19            new renewable energy facility located or to be 
20            located at or adjacent to the site at which the 
21            electric generating facility is located;
22                (5) the electric generating facility located 
23            at the site was at one time owned, in whole or in 
24            part, by a public utility as defined in Section 
25            3-105 of the Public Utilities Act;
26                (6) the electric generating facility at the 
 
 
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1            site is not owned by (i) an electric cooperative 
2            as defined in Section 3-119 of the Public 
3            Utilities Act, or (ii) an entity described in 
4            subsection (b)(1) of Section 3-105 of the Public 
5            Utilities Act, or an association or consortium of 
6            or an entity owned by entities described in items 
7            (i) or (ii);
8                (7) the proposed energy storage facility at 
9            the site will have energy storage capacity of at 
10            least 37 megawatts;
11                (8) the owner commits to place the energy 
12            storage facility into commercial operation on 
13            either June 1, 2023, June 1, 2024, or June 1, 2025, 
14            with such date subject to adjustment as needed due 
15            to any delays in completing the grant contracting 
16            process, in finalizing interconnection agreements 
17            and in installing interconnection facilities, and 
18            in obtaining necessary governmental permits and 
19            approvals;
20                (9) the owner agrees that the new energy 
21            storage facility will be constructed or installed 
22            by a qualified entity or entities consistent with 
23            the requirements of subsection (g) of Section 
24            16-128A of the Public Utilities Act and any rules 
25            adopted under that Section;
26                (10) the owner agrees that personnel operating 
 
 
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1            the energy storage facility will have the 
2            requisite skills, knowledge, training, experience, 
3            and competence, which may be demonstrated by 
4            completion or current participation and ultimate 
5            completion by employees of an accredited or 
6            otherwise recognized apprenticeship program for 
7            the employee's particular craft, trade, or skill, 
8            including through training and education courses 
9            and opportunities offered by the owner to 
10            employees of the coal-fueled electric generating 
11            facility or by previous employment experience 
12            performing the employee's particular work skill or 
13            function;
14                (11) the owner commits that not less than the 
15            prevailing wage, as determined pursuant to the 
16            Prevailing Wage Act, will be paid to the owner's 
17            employees engaged in construction activities 
18            associated with the new energy storage facility 
19            and to the employees of the owner's contractors 
20            engaged in construction activities associated with 
21            the new energy storage facility, and that, on or 
22            before the commercial operation date of the new 
23            energy storage facility, the owner shall file a 
24            report with the Department certifying that the 
25            requirements of this subparagraph (11) have been 
26            met; and
 
 
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1                (12) the owner commits that if selected to 
2            receive a grant, it will negotiate a project labor 
3            agreement for the construction of the new energy 
4            storage facility that includes provisions 
5            requiring the parties to the agreement to work 
6            together to establish diversity threshold 
7            requirements and to ensure best efforts to meet 
8            diversity targets, improve diversity at the 
9            applicable job site, create diverse apprenticeship 
10            opportunities, and create opportunities to employ 
11            former coal-fired power plant workers.
12            The Department shall accept applications for this 
13        grant program until March 31, 2022 and shall announce 
14        the award of grants no later than June 1, 2022. The 
15        Department shall make the grant payments to a 
16        recipient in equal annual amounts for 10 years 
17        following the date the energy storage facility is 
18        placed into commercial operation. The annual grant 
19        payments to a qualifying energy storage facility shall 
20        be $110,000 per megawatt of energy storage capacity, 
21        with total annual grant payments pursuant to this 
22        subparagraph (C) for qualifying energy storage 
23        facilities not to exceed $28,050,000 in any year.
24            (D) Grants of funding for energy storage 
25        facilities pursuant to subparagraph (C) of this 
26        paragraph (10), from the Coal to Solar and Energy 
 
 
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1        Storage Initiative Fund, shall be memorialized in 
2        grant contracts between the Department and the 
3        recipient. The grant contracts shall specify the date 
4        or dates in each year on which the annual grant 
5        payments shall be paid.
6            (E) All disbursements from the Coal to Solar and 
7        Energy Storage Initiative Fund shall be made only upon 
8        warrants of the Comptroller drawn upon the Treasurer 
9        as custodian of the Fund upon vouchers signed by the 
10        Director of the Department or by the person or persons 
11        designated by the Director of the Department for that 
12        purpose. The Comptroller is authorized to draw the 
13        warrants upon vouchers so signed. The Treasurer shall 
14        accept all written warrants so signed and shall be 
15        released from liability for all payments made on those 
16        warrants.
17        (11) Diversity, equity, and inclusion plans.
18            (A) Each applicant selected in a procurement event 
19        to contract to supply renewable energy credits in 
20        accordance with this subsection (c-5) and each owner 
21        selected by the Department to receive a grant or 
22        grants to support the construction and operation of a 
23        new energy storage facility or facilities in 
24        accordance with this subsection (c-5) shall, within 60 
25        days following the Commission's approval of the 
26        applicant to contract to supply renewable energy 
 
 
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1        credits or within 60 days following execution of a 
2        grant contract with the Department, as applicable, 
3        submit to the Commission a diversity, equity, and 
4        inclusion plan setting forth the applicant's or 
5        owner's numeric goals for the diversity composition of 
6        its supplier entities for the new renewable energy 
7        facility or new energy storage facility, as 
8        applicable, which shall be referred to for purposes of 
9        this paragraph (11) as the project, and the 
10        applicant's or owner's action plan and schedule for 
11        achieving those goals.
12            (B) For purposes of this paragraph (11), diversity 
13        composition shall be based on the percentage, which 
14        shall be a minimum of 25%, of eligible expenditures 
15        for contract awards for materials and services (which 
16        shall be defined in the plan) to business enterprises 
17        owned by minority persons, women, or persons with 
18        disabilities as defined in Section 2 of the Business 
19        Enterprise for Minorities, Women, and Persons with 
20        Disabilities Act, to LGBTQ business enterprises, to 
21        veteran-owned business enterprises, and to business 
22        enterprises located in environmental justice 
23        communities. The diversity composition goals of the 
24        plan may include eligible expenditures in areas for 
25        vendor or supplier opportunities in addition to 
26        development and construction of the project, and may 
 
 
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1        exclude from eligible expenditures materials and 
2        services with limited market availability, limited 
3        production and availability from suppliers in the 
4        United States, such as solar panels and storage 
5        batteries, and material and services that are subject 
6        to critical energy infrastructure or cybersecurity 
7        requirements or restrictions. The plan may provide 
8        that the diversity composition goals may be met 
9        through Tier 1 Direct or Tier 2 subcontracting 
10        expenditures or a combination thereof for the project.
11            (C) The plan shall provide for, but not be limited 
12        to: (i) internal initiatives, including multi-tier 
13        initiatives, by the applicant or owner, or by its 
14        engineering, procurement and construction contractor 
15        if one is used for the project, which for purposes of 
16        this paragraph (11) shall be referred to as the EPC 
17        contractor, to enable diverse businesses to be 
18        considered fairly for selection to provide materials 
19        and services; (ii) requirements for the applicant or 
20        owner or its EPC contractor to proactively solicit and 
21        utilize diverse businesses to provide materials and 
22        services; and (iii) requirements for the applicant or 
23        owner or its EPC contractor to hire a diverse 
24        workforce for the project. The plan shall include a 
25        description of the applicant's or owner's diversity 
26        recruiting efforts both for the project and for other 
 
 
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1        areas of the applicant's or owner's business 
2        operations. The plan shall provide for the imposition 
3        of financial penalties on the applicant's or owner's 
4        EPC contractor for failure to exercise best efforts to 
5        comply with and execute the EPC contractor's diversity 
6        obligations under the plan. The plan may provide for 
7        the applicant or owner to set aside a portion of the 
8        work on the project to serve as an incubation program 
9        for qualified businesses, as specified in the plan, 
10        owned by minority persons, women, persons with 
11        disabilities, LGBTQ persons, and veterans, and 
12        businesses located in environmental justice 
13        communities, seeking to enter the renewable energy 
14        industry.
15            (D) The applicant or owner may submit a revised or 
16        updated plan to the Commission from time to time as 
17        circumstances warrant. The applicant or owner shall 
18        file annual reports with the Commission detailing the 
19        applicant's or owner's progress in implementing its 
20        plan and achieving its goals and any modifications the 
21        applicant or owner has made to its plan to better 
22        achieve its diversity, equity and inclusion goals. The 
23        applicant or owner shall file a final report on the 
24        fifth June 1 following the commercial operation date 
25        of the new renewable energy resource or new energy 
26        storage facility, but the applicant or owner shall 
 
 
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1        thereafter continue to be subject to applicable 
2        reporting requirements of Section 5-117 of the Public 
3        Utilities Act. 
4    (c-10) Equity accountability system. It is the purpose of 
5this subsection (c-10) to create an equity accountability 
6system, which includes the minimum equity standards for all 
7renewable energy procurements, the equity category of the 
8Adjustable Block Program, and the equity prioritization for 
9noncompetitive procurements, that is successful in advancing 
10priority access to the clean energy economy for businesses and 
11workers from communities that have been excluded from economic 
12opportunities in the energy sector, have been subject to 
13disproportionate levels of pollution, and have 
14disproportionately experienced negative public health 
15outcomes. Further, it is the purpose of this subsection to 
16ensure that this equity accountability system is successful in 
17advancing equity across Illinois by providing access to the 
18clean energy economy for businesses and workers from 
19communities that have been historically excluded from economic 
20opportunities in the energy sector, have been subject to 
21disproportionate levels of pollution, and have 
22disproportionately experienced negative public health 
23outcomes.
24        (1) Minimum equity standards. The Agency shall create 
25    programs with the purpose of increasing access to and 
26    development of equity eligible contractors, who are prime 
 
 
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1    contractors and subcontractors, across all of the programs 
2    it manages. All applications for renewable energy credit 
3    procurements shall comply with specific minimum equity 
4    commitments. Starting in the delivery year immediately 
5    following the next long-term renewable resources 
6    procurement plan, at least 10% of the project workforce 
7    for each entity participating in a procurement program 
8    outlined in this subsection (c-10) must be done by equity 
9    eligible persons or equity eligible contractors. The 
10    Agency shall increase the minimum percentage each delivery 
11    year thereafter by increments that ensure a statewide 
12    average of 30% of the project workforce for each entity 
13    participating in a procurement program is done by equity 
14    eligible persons or equity eligible contractors by 2030. 
15    The Agency shall propose a schedule of percentage 
16    increases to the minimum equity standards in its draft 
17    revised renewable energy resources procurement plan 
18    submitted to the Commission for approval pursuant to 
19    paragraph (5) of subsection (b) of Section 16-111.5 of the 
20    Public Utilities Act. In determining these annual 
21    increases, the Agency shall have the discretion to 
22    establish different minimum equity standards for different 
23    types of procurements and different regions of the State 
24    if the Agency finds that doing so will further the 
25    purposes of this subsection (c-10). The proposed schedule 
26    of annual increases shall be revisited and updated on an 
 
 
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1    annual basis. Revisions shall be developed with 
2    stakeholder input, including from equity eligible persons, 
3    equity eligible contractors, clean energy industry 
4    representatives, and community-based organizations that 
5    work with such persons and contractors.
6            (A) At the start of each delivery year, the Agency 
7        shall require a compliance plan from each entity 
8        participating in a procurement program of subsection 
9        (c) of this Section, and entities opting to comply 
10        with the minimum equity standard through the Illinois 
11        Solar for All Program under Section 1-56 of this Act,    
12        that demonstrates how they will achieve compliance 
13        with the minimum equity standard percentage for work 
14        completed in that delivery year. If an entity applies 
15        for its approved vendor or designee status between 
16        delivery years, the Agency shall require a compliance 
17        plan at the time of application.
18            (B) Halfway through each delivery year, the Agency 
19        shall require each entity participating in a 
20        procurement program to confirm that it will achieve 
21        compliance in that delivery year, when applicable. The 
22        Agency may offer corrective action plans to entities 
23        that are not on track to achieve compliance.
24            (C) At the end of each delivery year, each entity 
25        participating and completing work in that delivery 
26        year in a procurement program of subsection (c) shall 
 
 
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1        submit a report to the Agency that demonstrates how it 
2        achieved compliance with the minimum equity standards 
3        percentage for that delivery year.
4            (D) The Agency shall prohibit participation in 
5        procurement programs by an approved vendor or 
6        designee, as applicable, or entities with which an 
7        approved vendor or designee, as applicable, shares a 
8        common parent company if an approved vendor or 
9        designee, as applicable, failed to meet the minimum 
10        equity standards for the prior delivery year. Waivers 
11        approved for lack of equity eligible persons or equity 
12        eligible contractors in a geographic area of a project 
13        shall not count against the approved vendor or 
14        designee. The Agency shall offer a corrective action 
15        plan for any such entities to assist them in obtaining 
16        compliance and shall allow continued access to 
17        procurement programs upon an approved vendor or 
18        designee demonstrating compliance.
19            (E) The Agency shall pursue efficiencies achieved 
20        by combining with other approved vendor or designee 
21        reporting.
22        (2) Equity accountability system within the Adjustable 
23    Block program. The equity category described in item (vi) 
24    of subparagraph (K) of subsection (c) is only available to 
25    applicants that are equity eligible contractors.
26        (3) Equity accountability system within competitive 
 
 
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1    procurements. Through its long-term renewable resources 
2    procurement plan, the Agency shall develop requirements 
3    for ensuring that competitive procurement processes, 
4    including utility-scale solar, utility-scale wind, and 
5    brownfield site photovoltaic projects, advance the equity 
6    goals of this subsection (c-10). Subject to Commission 
7    approval, the Agency shall develop bid application 
8    requirements and a bid evaluation methodology for ensuring 
9    that utilization of equity eligible contractors, whether 
10    as bidders or as participants on project development, is 
11    optimized, including requiring that winning or successful 
12    applicants for utility-scale projects are or will partner 
13    with equity eligible contractors and giving preference to 
14    bids through which a higher portion of contract value 
15    flows to equity eligible contractors. To the extent 
16    practicable, entities participating in competitive 
17    procurements shall also be required to meet all the equity 
18    accountability requirements for approved vendors and their 
19    designees under this subsection (c-10). In developing 
20    these requirements, the Agency shall also consider whether 
21    equity goals can be further advanced through additional 
22    measures.
23        (4) In the first revision to the long-term renewable 
24    energy resources procurement plan and each revision 
25    thereafter, the Agency shall include the following:
26            (A) The current status and number of equity 
 
 
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1        eligible contractors listed in the Energy Workforce 
2        Equity Database designed in subsection (c-25), 
3        including the number of equity eligible contractors 
4        with current certifications as issued by the Agency.
5            (B) A mechanism for measuring, tracking, and 
6        reporting project workforce at the approved vendor or 
7        designee level, as applicable, which shall include a 
8        measurement methodology and records to be made 
9        available for audit by the Agency or the Program 
10        Administrator.
11            (C) A program for approved vendors, designees, 
12        eligible persons, and equity eligible contractors to 
13        receive trainings, guidance, and other support from 
14        the Agency or its designee regarding the equity 
15        category outlined in item (vi) of subparagraph (K) of 
16        paragraph (1) of subsection (c) and in meeting the 
17        minimum equity standards of this subsection (c-10).
18            (D) A process for certifying equity eligible 
19        contractors and equity eligible persons. The 
20        certification process shall coordinate with the Energy 
21        Workforce Equity Database set forth in subsection 
22        (c-25).
23            (E) An application for waiver of the minimum 
24        equity standards of this subsection, which the Agency 
25        shall have the discretion to grant in rare 
26        circumstances. The Agency may grant such a waiver 
 
 
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1        where the applicant provides evidence of significant 
2        efforts toward meeting the minimum equity commitment, 
3        including: use of the Energy Workforce Equity 
4        Database; efforts to hire or contract with entities 
5        that hire eligible persons; and efforts to establish 
6        contracting relationships with eligible contractors. 
7        The Agency shall support applicants in understanding 
8        the Energy Workforce Equity Database and other 
9        resources for pursuing compliance of the minimum 
10        equity standards. Waivers shall be project-specific, 
11        unless the Agency deems it necessary to grant a waiver 
12        across a portfolio of projects, and in effect for no 
13        longer than one year. Any waiver extension or 
14        subsequent waiver request from an applicant shall be 
15        subject to the requirements of this Section and shall 
16        specify efforts made to reach compliance. When 
17        considering whether to grant a waiver, and to what 
18        extent, the Agency shall consider the degree to which 
19        similarly situated applicants have been able to meet 
20        these minimum equity commitments. For repeated waiver 
21        requests for specific lack of eligible persons or 
22        eligible contractors available, the Agency shall make 
23        recommendations to target recruitment to add such 
24        eligible persons or eligible contractors to the 
25        database.
26        (5) The Agency shall collect information about work on 
 
 
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1    projects or portfolios of projects subject to these 
2    minimum equity standards to ensure compliance with this 
3    subsection (c-10). Reporting in furtherance of this 
4    requirement may be combined with other annual reporting 
5    requirements. Such reporting shall include proof of 
6    certification of each equity eligible contractor or equity 
7    eligible person during the applicable time period.
8        (6) The Agency shall keep confidential all information 
9    and communication that provides private or personal 
10    information.
11        (7) Modifications to the equity accountability system. 
12    As part of the update of the long-term renewable resources 
13    procurement plan to be initiated in 2023, or sooner if the 
14    Agency deems necessary, the Agency shall determine the 
15    extent to which the equity accountability system described 
16    in this subsection (c-10) has advanced the goals of this 
17    amendatory Act of the 102nd General Assembly, including 
18    through the inclusion of equity eligible persons and 
19    equity eligible contractors in renewable energy credit 
20    projects. If the Agency finds that the equity 
21    accountability system has failed to meet those goals to 
22    its fullest potential, the Agency may revise the following 
23    criteria for future Agency procurements: (A) the 
24    percentage of project workforce, or other appropriate 
25    workforce measure, certified as equity eligible persons or 
26    equity eligible contractors; (B) definitions for equity 
 
 
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1    investment eligible persons and equity investment eligible 
2    community; and (C) such other modifications necessary to 
3    advance the goals of this amendatory Act of the 102nd 
4    General Assembly effectively. Such revised criteria may 
5    also establish distinct equity accountability systems for 
6    different types of procurements or different regions of 
7    the State if the Agency finds that doing so will further 
8    the purposes of such programs. Revisions shall be 
9    developed with stakeholder input, including from equity 
10    eligible persons, equity eligible contractors, and 
11    community-based organizations that work with such persons 
12    and contractors.
13    (c-15) Racial discrimination elimination powers and 
14process.
15        (1) Purpose. It is the purpose of this subsection to 
16    empower the Agency and other State actors to remedy racial 
17    discrimination in Illinois' clean energy economy as 
18    effectively and expediently as possible, including through 
19    the use of race-conscious remedies, such as race-conscious 
20    contracting and hiring goals, as consistent with State and 
21    federal law.
22        (2) Racial disparity and discrimination review 
23    process.
24            (A) Within one year after awarding contracts using 
25        the equity actions processes established in this 
26        Section, the Agency shall publish a report evaluating 
 
 
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1        the effectiveness of the equity actions point criteria 
2        of this Section in increasing participation of equity 
3        eligible persons and equity eligible contractors. The 
4        report shall disaggregate participating workers and 
5        contractors by race and ethnicity. The report shall be 
6        forwarded to the Governor, the General Assembly, and 
7        the Illinois Commerce Commission and be made available 
8        to the public.
9            (B) As soon as is practicable thereafter, the 
10        Agency, in consultation with the Department of 
11        Commerce and Economic Opportunity, Department of 
12        Labor, and other agencies that may be relevant, shall 
13        commission and publish a disparity and availability 
14        study that measures the presence and impact of 
15        discrimination on minority businesses and workers in 
16        Illinois' clean energy economy. The Agency may hire 
17        consultants and experts to conduct the disparity and 
18        availability study, with the retention of those 
19        consultants and experts exempt from the requirements 
20        of Section 20-10 of the Illinois Procurement Code. The 
21        Illinois Power Agency shall forward a copy of its 
22        findings and recommendations to the Governor, the 
23        General Assembly, and the Illinois Commerce 
24        Commission. If the disparity and availability study 
25        establishes a strong basis in evidence that there is 
26        discrimination in Illinois' clean energy economy, the 
 
 
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1        Agency, Department of Commerce and Economic 
2        Opportunity, Department of Labor, Department of 
3        Corrections, and other appropriate agencies shall take 
4        appropriate remedial actions, including race-conscious 
5        remedial actions as consistent with State and federal 
6        law, to effectively remedy this discrimination. Such 
7        remedies may include modification of the equity 
8        accountability system as described in subsection 
9        (c-10).
10    (c-20) Program data collection.
11        (1) Purpose. Data collection, data analysis, and 
12    reporting are critical to ensure that the benefits of the 
13    clean energy economy provided to Illinois residents and 
14    businesses are equitably distributed across the State. The 
15    Agency shall collect data from program applicants in order 
16    to track and improve equitable distribution of benefits 
17    across Illinois communities for all procurements the 
18    Agency conducts. The Agency shall use this data to, among 
19    other things, measure any potential impact of racial 
20    discrimination on the distribution of benefits and provide 
21    information necessary to correct any discrimination 
22    through methods consistent with State and federal law.
23        (2) Agency collection of program data. The Agency 
24    shall collect demographic and geographic data for each 
25    entity awarded contracts under any Agency-administered 
26    program.
 
 
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1        (3) Required information to be collected. The Agency 
2    shall collect the following information from applicants 
3    and program participants where applicable:
4            (A) demographic information, including racial or 
5        ethnic identity for real persons employed, contracted, 
6        or subcontracted through the program and owners of 
7        businesses or entities that apply to receive renewable 
8        energy credits from the Agency;
9            (B) geographic location of the residency of real 
10        persons employed, contracted, or subcontracted through 
11        the program and geographic location of the 
12        headquarters of the business or entity that applies to 
13        receive renewable energy credits from the Agency; and
14            (C) any other information the Agency determines is 
15        necessary for the purpose of achieving the purpose of 
16        this subsection.
17        (4) Publication of collected information. The Agency 
18    shall publish, at least annually, information on the 
19    demographics of program participants on an aggregate 
20    basis.
21        (5) Nothing in this subsection shall be interpreted to 
22    limit the authority of the Agency, or other agency or 
23    department of the State, to require or collect demographic 
24    information from applicants of other State programs.
25    (c-25) Energy Workforce Equity Database.
26        (1) The Agency, in consultation with the Department of 
 
 
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1    Commerce and Economic Opportunity, shall create an Energy 
2    Workforce Equity Database, and may contract with a third 
3    party to do so ("database program administrator"). If the 
4    Department decides to contract with a third party, that 
5    third party shall be exempt from the requirements of 
6    Section 20-10 of the Illinois Procurement Code. The Energy 
7    Workforce Equity Database shall be a searchable database 
8    of suppliers, vendors, and subcontractors for clean energy 
9    industries that is:
10            (A) publicly accessible;
11            (B) easy for people to find and use;
12            (C) organized by company specialty or field;
13            (D) region-specific; and
14            (E) populated with information including, but not 
15        limited to, contacts for suppliers, vendors, or 
16        subcontractors who are minority and women-owned 
17        business enterprise certified or who participate or 
18        have participated in any of the programs described in 
19        this Act.
20        (2) The Agency shall create an easily accessible, 
21    public facing online tool using the database information 
22    that includes, at a minimum, the following:
23            (A) a map of environmental justice and equity 
24        investment eligible communities;
25            (B) job postings and recruiting opportunities;
26            (C) a means by which recruiting clean energy 
 
 
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1        companies can find and interact with current or former 
2        participants of clean energy workforce training 
3        programs;
4            (D) information on workforce training service 
5        providers and training opportunities available to 
6        prospective workers;
7            (E) renewable energy company diversity reporting;
8            (F) a list of equity eligible contractors with 
9        their contact information, types of work performed, 
10        and locations worked in;
11            (G) reporting on outcomes of the programs 
12        described in the workforce programs of the Energy 
13        Transition Act, including information such as, but not 
14        limited to, retention rate, graduation rate, and 
15        placement rates of trainees; and
16            (H) information about the Jobs and Environmental 
17        Justice Grant Program, the Clean Energy Jobs and 
18        Justice Fund, and other sources of capital.
19        (3) The Agency shall ensure the database is regularly 
20    updated to ensure information is current and shall 
21    coordinate with the Department of Commerce and Economic 
22    Opportunity to ensure that it includes information on 
23    individuals and entities that are or have participated in 
24    the Clean Jobs Workforce Network Program, Clean Energy 
25    Contractor Incubator Program, Returning Residents Clean 
26    Jobs Training Program, or Clean Energy Primes Contractor 
 
 
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1    Accelerator Program.
2    (c-30) Enforcement of minimum equity standards. All 
3entities seeking renewable energy credits must submit an 
4annual report to demonstrate compliance with each of the 
5equity commitments required under subsection (c-10). If the 
6Agency concludes the entity has not met or maintained its 
7minimum equity standards required under the applicable 
8subparagraphs under subsection (c-10), the Agency shall deny 
9the entity's ability to participate in procurement programs in 
10subsection (c), including by withholding approved vendor or 
11designee status. The Agency may require the entity to enter 
12into a corrective action plan. An entity that is not 
13recertified for failing to meet required equity actions in 
14subparagraph (c-10) may reapply once they have a corrective 
15action plan and achieve compliance with the minimum equity 
16standards.
17    (d) Clean coal portfolio standard.
18        (1) The procurement plans shall include electricity 
19    generated using clean coal. Each utility shall enter into 
20    one or more sourcing agreements with the initial clean 
21    coal facility, as provided in paragraph (3) of this 
22    subsection (d), covering electricity generated by the 
23    initial clean coal facility representing at least 5% of 
24    each utility's total supply to serve the load of eligible 
25    retail customers in 2015 and each year thereafter, as 
26    described in paragraph (3) of this subsection (d), subject 
 
 
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1    to the limits specified in paragraph (2) of this 
2    subsection (d). It is the goal of the State that by January 
3    1, 2025, 25% of the electricity used in the State shall be 
4    generated by cost-effective clean coal facilities. For 
5    purposes of this subsection (d), "cost-effective" means 
6    that the expenditures pursuant to such sourcing agreements 
7    do not cause the limit stated in paragraph (2) of this 
8    subsection (d) to be exceeded and do not exceed cost-based 
9    benchmarks, which shall be developed to assess all 
10    expenditures pursuant to such sourcing agreements covering 
11    electricity generated by clean coal facilities, other than 
12    the initial clean coal facility, by the procurement 
13    administrator, in consultation with the Commission staff, 
14    Agency staff, and the procurement monitor and shall be 
15    subject to Commission review and approval.
16        A utility party to a sourcing agreement shall 
17    immediately retire any emission credits that it receives 
18    in connection with the electricity covered by such 
19    agreement.
20        Utilities shall maintain adequate records documenting 
21    the purchases under the sourcing agreement to comply with 
22    this subsection (d) and shall file an accounting with the 
23    load forecast that must be filed with the Agency by July 15 
24    of each year, in accordance with subsection (d) of Section 
25    16-111.5 of the Public Utilities Act.
26        A utility shall be deemed to have complied with the 
 
 
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1    clean coal portfolio standard specified in this subsection 
2    (d) if the utility enters into a sourcing agreement as 
3    required by this subsection (d). 
4        (2) For purposes of this subsection (d), the required 
5    execution of sourcing agreements with the initial clean 
6    coal facility for a particular year shall be measured as a 
7    percentage of the actual amount of electricity 
8    (megawatt-hours) supplied by the electric utility to 
9    eligible retail customers in the planning year ending 
10    immediately prior to the agreement's execution. For 
11    purposes of this subsection (d), the amount paid per 
12    kilowatthour means the total amount paid for electric 
13    service expressed on a per kilowatthour basis. For 
14    purposes of this subsection (d), the total amount paid for 
15    electric service includes without limitation amounts paid 
16    for supply, transmission, distribution, surcharges and 
17    add-on taxes.
18        Notwithstanding the requirements of this subsection 
19    (d), the total amount paid under sourcing agreements with 
20    clean coal facilities pursuant to the procurement plan for 
21    any given year shall be reduced by an amount necessary to 
22    limit the annual estimated average net increase due to the 
23    costs of these resources included in the amounts paid by 
24    eligible retail customers in connection with electric 
25    service to:
26            (A) in 2010, no more than 0.5% of the amount paid 
 
 
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1        per kilowatthour by those customers during the year 
2        ending May 31, 2009;
3            (B) in 2011, the greater of an additional 0.5% of 
4        the amount paid per kilowatthour by those customers 
5        during the year ending May 31, 2010 or 1% of the amount 
6        paid per kilowatthour by those customers during the 
7        year ending May 31, 2009;
8            (C) in 2012, the greater of an additional 0.5% of 
9        the amount paid per kilowatthour by those customers 
10        during the year ending May 31, 2011 or 1.5% of the 
11        amount paid per kilowatthour by those customers during 
12        the year ending May 31, 2009;
13            (D) in 2013, the greater of an additional 0.5% of 
14        the amount paid per kilowatthour by those customers 
15        during the year ending May 31, 2012 or 2% of the amount 
16        paid per kilowatthour by those customers during the 
17        year ending May 31, 2009; and
18            (E) thereafter, the total amount paid under 
19        sourcing agreements with clean coal facilities 
20        pursuant to the procurement plan for any single year 
21        shall be reduced by an amount necessary to limit the 
22        estimated average net increase due to the cost of 
23        these resources included in the amounts paid by 
24        eligible retail customers in connection with electric 
25        service to no more than the greater of (i) 2.015% of 
26        the amount paid per kilowatthour by those customers 
 
 
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1        during the year ending May 31, 2009 or (ii) the 
2        incremental amount per kilowatthour paid for these 
3        resources in 2013. These requirements may be altered 
4        only as provided by statute.
5        No later than June 30, 2015, the Commission shall 
6    review the limitation on the total amount paid under 
7    sourcing agreements, if any, with clean coal facilities 
8    pursuant to this subsection (d) and report to the General 
9    Assembly its findings as to whether that limitation unduly 
10    constrains the amount of electricity generated by 
11    cost-effective clean coal facilities that is covered by 
12    sourcing agreements.
13        (3) Initial clean coal facility. In order to promote 
14    development of clean coal facilities in Illinois, each 
15    electric utility subject to this Section shall execute a 
16    sourcing agreement to source electricity from a proposed 
17    clean coal facility in Illinois (the "initial clean coal 
18    facility") that will have a nameplate capacity of at least 
19    500 MW when commercial operation commences, that has a 
20    final Clean Air Act permit on June 1, 2009 (the effective 
21    date of Public Act 95-1027), and that will meet the 
22    definition of clean coal facility in Section 1-10 of this 
23    Act when commercial operation commences. The sourcing 
24    agreements with this initial clean coal facility shall be 
25    subject to both approval of the initial clean coal 
26    facility by the General Assembly and satisfaction of the 
 
 
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1    requirements of paragraph (4) of this subsection (d) and 
2    shall be executed within 90 days after any such approval 
3    by the General Assembly. The Agency and the Commission 
4    shall have authority to inspect all books and records 
5    associated with the initial clean coal facility during the 
6    term of such a sourcing agreement. A utility's sourcing 
7    agreement for electricity produced by the initial clean 
8    coal facility shall include:
9            (A) a formula contractual price (the "contract 
10        price") approved pursuant to paragraph (4) of this 
11        subsection (d), which shall:
12                (i) be determined using a cost of service 
13            methodology employing either a level or deferred 
14            capital recovery component, based on a capital 
15            structure consisting of 45% equity and 55% debt, 
16            and a return on equity as may be approved by the 
17            Federal Energy Regulatory Commission, which in any 
18            case may not exceed the lower of 11.5% or the rate 
19            of return approved by the General Assembly 
20            pursuant to paragraph (4) of this subsection (d); 
21            and
22                (ii) provide that all miscellaneous net 
23            revenue, including but not limited to net revenue 
24            from the sale of emission allowances, if any, 
25            substitute natural gas, if any, grants or other 
26            support provided by the State of Illinois or the 
 
 
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1            United States Government, firm transmission 
2            rights, if any, by-products produced by the 
3            facility, energy or capacity derived from the 
4            facility and not covered by a sourcing agreement 
5            pursuant to paragraph (3) of this subsection (d) 
6            or item (5) of subsection (d) of Section 16-115 of 
7            the Public Utilities Act, whether generated from 
8            the synthesis gas derived from coal, from SNG, or 
9            from natural gas, shall be credited against the 
10            revenue requirement for this initial clean coal 
11            facility;
12            (B) power purchase provisions, which shall: 
13                (i) provide that the utility party to such 
14            sourcing agreement shall pay the contract price 
15            for electricity delivered under such sourcing 
16            agreement; 
17                (ii) require delivery of electricity to the 
18            regional transmission organization market of the 
19            utility that is party to such sourcing agreement;
20                (iii) require the utility party to such 
21            sourcing agreement to buy from the initial clean 
22            coal facility in each hour an amount of energy 
23            equal to all clean coal energy made available from 
24            the initial clean coal facility during such hour 
25            times a fraction, the numerator of which is such 
26            utility's retail market sales of electricity 
 
 
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1            (expressed in kilowatthours sold) in the State 
2            during the prior calendar month and the 
3            denominator of which is the total retail market 
4            sales of electricity (expressed in kilowatthours 
5            sold) in the State by utilities during such prior 
6            month and the sales of electricity (expressed in 
7            kilowatthours sold) in the State by alternative 
8            retail electric suppliers during such prior month 
9            that are subject to the requirements of this 
10            subsection (d) and paragraph (5) of subsection (d) 
11            of Section 16-115 of the Public Utilities Act, 
12            provided that the amount purchased by the utility 
13            in any year will be limited by paragraph (2) of 
14            this subsection (d); and
15                (iv) be considered pre-existing contracts in 
16            such utility's procurement plans for eligible 
17            retail customers;
18            (C) contract for differences provisions, which 
19        shall:
20                (i) require the utility party to such sourcing 
21            agreement to contract with the initial clean coal 
22            facility in each hour with respect to an amount of 
23            energy equal to all clean coal energy made 
24            available from the initial clean coal facility 
25            during such hour times a fraction, the numerator 
26            of which is such utility's retail market sales of 
 
 
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1            electricity (expressed in kilowatthours sold) in 
2            the utility's service territory in the State 
3            during the prior calendar month and the 
4            denominator of which is the total retail market 
5            sales of electricity (expressed in kilowatthours 
6            sold) in the State by utilities during such prior 
7            month and the sales of electricity (expressed in 
8            kilowatthours sold) in the State by alternative 
9            retail electric suppliers during such prior month 
10            that are subject to the requirements of this 
11            subsection (d) and paragraph (5) of subsection (d) 
12            of Section 16-115 of the Public Utilities Act, 
13            provided that the amount paid by the utility in 
14            any year will be limited by paragraph (2) of this 
15            subsection (d);
16                (ii) provide that the utility's payment 
17            obligation in respect of the quantity of 
18            electricity determined pursuant to the preceding 
19            clause (i) shall be limited to an amount equal to 
20            (1) the difference between the contract price 
21            determined pursuant to subparagraph (A) of 
22            paragraph (3) of this subsection (d) and the 
23            day-ahead price for electricity delivered to the 
24            regional transmission organization market of the 
25            utility that is party to such sourcing agreement 
26            (or any successor delivery point at which such 
 
 
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1            utility's supply obligations are financially 
2            settled on an hourly basis) (the "reference 
3            price") on the day preceding the day on which the 
4            electricity is delivered to the initial clean coal 
5            facility busbar, multiplied by (2) the quantity of 
6            electricity determined pursuant to the preceding 
7            clause (i); and
8                (iii) not require the utility to take physical 
9            delivery of the electricity produced by the 
10            facility;
11            (D) general provisions, which shall:
12                (i) specify a term of no more than 30 years, 
13            commencing on the commercial operation date of the 
14            facility;
15                (ii) provide that utilities shall maintain 
16            adequate records documenting purchases under the 
17            sourcing agreements entered into to comply with 
18            this subsection (d) and shall file an accounting 
19            with the load forecast that must be filed with the 
20            Agency by July 15 of each year, in accordance with 
21            subsection (d) of Section 16-111.5 of the Public 
22            Utilities Act; 
23                (iii) provide that all costs associated with 
24            the initial clean coal facility will be 
25            periodically reported to the Federal Energy 
26            Regulatory Commission and to purchasers in 
 
 
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1            accordance with applicable laws governing 
2            cost-based wholesale power contracts;
3                (iv) permit the Illinois Power Agency to 
4            assume ownership of the initial clean coal 
5            facility, without monetary consideration and 
6            otherwise on reasonable terms acceptable to the 
7            Agency, if the Agency so requests no less than 3 
8            years prior to the end of the stated contract 
9            term;
10                (v) require the owner of the initial clean 
11            coal facility to provide documentation to the 
12            Commission each year, starting in the facility's 
13            first year of commercial operation, accurately 
14            reporting the quantity of carbon emissions from 
15            the facility that have been captured and 
16            sequestered and report any quantities of carbon 
17            released from the site or sites at which carbon 
18            emissions were sequestered in prior years, based 
19            on continuous monitoring of such sites. If, in any 
20            year after the first year of commercial operation, 
21            the owner of the facility fails to demonstrate 
22            that the initial clean coal facility captured and 
23            sequestered at least 50% of the total carbon 
24            emissions that the facility would otherwise emit 
25            or that sequestration of emissions from prior 
26            years has failed, resulting in the release of 
 
 
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1            carbon dioxide into the atmosphere, the owner of 
2            the facility must offset excess emissions. Any 
3            such carbon offsets must be permanent, additional, 
4            verifiable, real, located within the State of 
5            Illinois, and legally and practicably enforceable. 
6            The cost of such offsets for the facility that are 
7            not recoverable shall not exceed $15 million in 
8            any given year. No costs of any such purchases of 
9            carbon offsets may be recovered from a utility or 
10            its customers. All carbon offsets purchased for 
11            this purpose and any carbon emission credits 
12            associated with sequestration of carbon from the 
13            facility must be permanently retired. The initial 
14            clean coal facility shall not forfeit its 
15            designation as a clean coal facility if the 
16            facility fails to fully comply with the applicable 
17            carbon sequestration requirements in any given 
18            year, provided the requisite offsets are 
19            purchased. However, the Attorney General, on 
20            behalf of the People of the State of Illinois, may 
21            specifically enforce the facility's sequestration 
22            requirement and the other terms of this contract 
23            provision. Compliance with the sequestration 
24            requirements and offset purchase requirements 
25            specified in paragraph (3) of this subsection (d) 
26            shall be reviewed annually by an independent 
 
 
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1            expert retained by the owner of the initial clean 
2            coal facility, with the advance written approval 
3            of the Attorney General. The Commission may, in 
4            the course of the review specified in item (vii), 
5            reduce the allowable return on equity for the 
6            facility if the facility willfully fails to comply 
7            with the carbon capture and sequestration 
8            requirements set forth in this item (v);
9                (vi) include limits on, and accordingly 
10            provide for modification of, the amount the 
11            utility is required to source under the sourcing 
12            agreement consistent with paragraph (2) of this 
13            subsection (d);
14                (vii) require Commission review: (1) to 
15            determine the justness, reasonableness, and 
16            prudence of the inputs to the formula referenced 
17            in subparagraphs (A)(i) through (A)(iii) of 
18            paragraph (3) of this subsection (d), prior to an 
19            adjustment in those inputs including, without 
20            limitation, the capital structure and return on 
21            equity, fuel costs, and other operations and 
22            maintenance costs and (2) to approve the costs to 
23            be passed through to customers under the sourcing 
24            agreement by which the utility satisfies its 
25            statutory obligations. Commission review shall 
26            occur no less than every 3 years, regardless of 
 
 
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1            whether any adjustments have been proposed, and 
2            shall be completed within 9 months; 
3                (viii) limit the utility's obligation to such 
4            amount as the utility is allowed to recover 
5            through tariffs filed with the Commission, 
6            provided that neither the clean coal facility nor 
7            the utility waives any right to assert federal 
8            pre-emption or any other argument in response to a 
9            purported disallowance of recovery costs;
10                (ix) limit the utility's or alternative retail 
11            electric supplier's obligation to incur any 
12            liability until such time as the facility is in 
13            commercial operation and generating power and 
14            energy and such power and energy is being 
15            delivered to the facility busbar;
16                (x) provide that the owner or owners of the 
17            initial clean coal facility, which is the 
18            counterparty to such sourcing agreement, shall 
19            have the right from time to time to elect whether 
20            the obligations of the utility party thereto shall 
21            be governed by the power purchase provisions or 
22            the contract for differences provisions;
23                (xi) append documentation showing that the 
24            formula rate and contract, insofar as they relate 
25            to the power purchase provisions, have been 
26            approved by the Federal Energy Regulatory 
 
 
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1            Commission pursuant to Section 205 of the Federal 
2            Power Act;
3                (xii) provide that any changes to the terms of 
4            the contract, insofar as such changes relate to 
5            the power purchase provisions, are subject to 
6            review under the public interest standard applied 
7            by the Federal Energy Regulatory Commission 
8            pursuant to Sections 205 and 206 of the Federal 
9            Power Act; and
10                (xiii) conform with customary lender 
11            requirements in power purchase agreements used as 
12            the basis for financing non-utility generators. 
13        (4) Effective date of sourcing agreements with the 
14    initial clean coal facility. Any proposed sourcing 
15    agreement with the initial clean coal facility shall not 
16    become effective unless the following reports are prepared 
17    and submitted and authorizations and approvals obtained:
18            (i) Facility cost report. The owner of the initial 
19        clean coal facility shall submit to the Commission, 
20        the Agency, and the General Assembly a front-end 
21        engineering and design study, a facility cost report, 
22        method of financing (including but not limited to 
23        structure and associated costs), and an operating and 
24        maintenance cost quote for the facility (collectively 
25        "facility cost report"), which shall be prepared in 
26        accordance with the requirements of this paragraph (4) 
 
 
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1        of subsection (d) of this Section, and shall provide 
2        the Commission and the Agency access to the work 
3        papers, relied upon documents, and any other backup 
4        documentation related to the facility cost report.
5            (ii) Commission report. Within 6 months following 
6        receipt of the facility cost report, the Commission, 
7        in consultation with the Agency, shall submit a report 
8        to the General Assembly setting forth its analysis of 
9        the facility cost report. Such report shall include, 
10        but not be limited to, a comparison of the costs 
11        associated with electricity generated by the initial 
12        clean coal facility to the costs associated with 
13        electricity generated by other types of generation 
14        facilities, an analysis of the rate impacts on 
15        residential and small business customers over the life 
16        of the sourcing agreements, and an analysis of the 
17        likelihood that the initial clean coal facility will 
18        commence commercial operation by and be delivering 
19        power to the facility's busbar by 2016. To assist in 
20        the preparation of its report, the Commission, in 
21        consultation with the Agency, may hire one or more 
22        experts or consultants, the costs of which shall be 
23        paid for by the owner of the initial clean coal 
24        facility. The Commission and Agency may begin the 
25        process of selecting such experts or consultants prior 
26        to receipt of the facility cost report.
 
 
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1            (iii) General Assembly approval. The proposed 
2        sourcing agreements shall not take effect unless, 
3        based on the facility cost report and the Commission's 
4        report, the General Assembly enacts authorizing 
5        legislation approving (A) the projected price, stated 
6        in cents per kilowatthour, to be charged for 
7        electricity generated by the initial clean coal 
8        facility, (B) the projected impact on residential and 
9        small business customers' bills over the life of the 
10        sourcing agreements, and (C) the maximum allowable 
11        return on equity for the project; and
12            (iv) Commission review. If the General Assembly 
13        enacts authorizing legislation pursuant to 
14        subparagraph (iii) approving a sourcing agreement, the 
15        Commission shall, within 90 days of such enactment, 
16        complete a review of such sourcing agreement. During 
17        such time period, the Commission shall implement any 
18        directive of the General Assembly, resolve any 
19        disputes between the parties to the sourcing agreement 
20        concerning the terms of such agreement, approve the 
21        form of such agreement, and issue an order finding 
22        that the sourcing agreement is prudent and reasonable.
23        The facility cost report shall be prepared as follows: 
24            (A) The facility cost report shall be prepared by 
25        duly licensed engineering and construction firms 
26        detailing the estimated capital costs payable to one 
 
 
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1        or more contractors or suppliers for the engineering, 
2        procurement and construction of the components 
3        comprising the initial clean coal facility and the 
4        estimated costs of operation and maintenance of the 
5        facility. The facility cost report shall include:
6                (i) an estimate of the capital cost of the 
7            core plant based on one or more front end 
8            engineering and design studies for the 
9            gasification island and related facilities. The 
10            core plant shall include all civil, structural, 
11            mechanical, electrical, control, and safety 
12            systems.
13                (ii) an estimate of the capital cost of the 
14            balance of the plant, including any capital costs 
15            associated with sequestration of carbon dioxide 
16            emissions and all interconnects and interfaces 
17            required to operate the facility, such as 
18            transmission of electricity, construction or 
19            backfeed power supply, pipelines to transport 
20            substitute natural gas or carbon dioxide, potable 
21            water supply, natural gas supply, water supply, 
22            water discharge, landfill, access roads, and coal 
23            delivery.
24            The quoted construction costs shall be expressed 
25        in nominal dollars as of the date that the quote is 
26        prepared and shall include capitalized financing costs 
 
 
10400SB0025ham002- 311 -LRB104 07069 AAS 28576 a

1        during construction, taxes, insurance, and other 
2        owner's costs, and an assumed escalation in materials 
3        and labor beyond the date as of which the construction 
4        cost quote is expressed.
5            (B) The front end engineering and design study for 
6        the gasification island and the cost study for the 
7        balance of plant shall include sufficient design work 
8        to permit quantification of major categories of 
9        materials, commodities and labor hours, and receipt of 
10        quotes from vendors of major equipment required to 
11        construct and operate the clean coal facility.
12            (C) The facility cost report shall also include an 
13        operating and maintenance cost quote that will provide 
14        the estimated cost of delivered fuel, personnel, 
15        maintenance contracts, chemicals, catalysts, 
16        consumables, spares, and other fixed and variable 
17        operations and maintenance costs. The delivered fuel 
18        cost estimate will be provided by a recognized third 
19        party expert or experts in the fuel and transportation 
20        industries. The balance of the operating and 
21        maintenance cost quote, excluding delivered fuel 
22        costs, will be developed based on the inputs provided 
23        by duly licensed engineering and construction firms 
24        performing the construction cost quote, potential 
25        vendors under long-term service agreements and plant 
26        operating agreements, or recognized third party plant 
 
 
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1        operator or operators.
2            The operating and maintenance cost quote 
3        (including the cost of the front end engineering and 
4        design study) shall be expressed in nominal dollars as 
5        of the date that the quote is prepared and shall 
6        include taxes, insurance, and other owner's costs, and 
7        an assumed escalation in materials and labor beyond 
8        the date as of which the operating and maintenance 
9        cost quote is expressed.
10            (D) The facility cost report shall also include an 
11        analysis of the initial clean coal facility's ability 
12        to deliver power and energy into the applicable 
13        regional transmission organization markets and an 
14        analysis of the expected capacity factor for the 
15        initial clean coal facility. 
16            (E) Amounts paid to third parties unrelated to the 
17        owner or owners of the initial clean coal facility to 
18        prepare the core plant construction cost quote, 
19        including the front end engineering and design study, 
20        and the operating and maintenance cost quote will be 
21        reimbursed through Coal Development Bonds.
22        (5) Re-powering and retrofitting coal-fired power 
23    plants previously owned by Illinois utilities to qualify 
24    as clean coal facilities. During the 2009 procurement 
25    planning process and thereafter, the Agency and the 
26    Commission shall consider sourcing agreements covering 
 
 
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1    electricity generated by power plants that were previously 
2    owned by Illinois utilities and that have been or will be 
3    converted into clean coal facilities, as defined by 
4    Section 1-10 of this Act. Pursuant to such procurement 
5    planning process, the owners of such facilities may 
6    propose to the Agency sourcing agreements with utilities 
7    and alternative retail electric suppliers required to 
8    comply with subsection (d) of this Section and item (5) of 
9    subsection (d) of Section 16-115 of the Public Utilities 
10    Act, covering electricity generated by such facilities. In 
11    the case of sourcing agreements that are power purchase 
12    agreements, the contract price for electricity sales shall 
13    be established on a cost of service basis. In the case of 
14    sourcing agreements that are contracts for differences, 
15    the contract price from which the reference price is 
16    subtracted shall be established on a cost of service 
17    basis. The Agency and the Commission may approve any such 
18    utility sourcing agreements that do not exceed cost-based 
19    benchmarks developed by the procurement administrator, in 
20    consultation with the Commission staff, Agency staff and 
21    the procurement monitor, subject to Commission review and 
22    approval. The Commission shall have authority to inspect 
23    all books and records associated with these clean coal 
24    facilities during the term of any such contract.
25        (6) Costs incurred under this subsection (d) or 
26    pursuant to a contract entered into under this subsection 
 
 
10400SB0025ham002- 314 -LRB104 07069 AAS 28576 a

1    (d) shall be deemed prudently incurred and reasonable in 
2    amount and the electric utility shall be entitled to full 
3    cost recovery pursuant to the tariffs filed with the 
4    Commission. 
5    (d-5) Zero emission standard.
6        (1) Beginning with the delivery year commencing on 
7    June 1, 2017, the Agency shall, for electric utilities 
8    that serve at least 100,000 retail customers in this 
9    State, procure contracts with zero emission facilities 
10    that are reasonably capable of generating cost-effective 
11    zero emission credits in an amount approximately equal to 
12    16% of the actual amount of electricity delivered by each 
13    electric utility to retail customers in the State during 
14    calendar year 2014. For an electric utility serving fewer 
15    than 100,000 retail customers in this State that 
16    requested, under Section 16-111.5 of the Public Utilities 
17    Act, that the Agency procure power and energy for all or a 
18    portion of the utility's Illinois load for the delivery 
19    year commencing June 1, 2016, the Agency shall procure 
20    contracts with zero emission facilities that are 
21    reasonably capable of generating cost-effective zero 
22    emission credits in an amount approximately equal to 16% 
23    of the portion of power and energy to be procured by the 
24    Agency for the utility. The duration of the contracts 
25    procured under this subsection (d-5) shall be for a term 
26    of 10 years ending May 31, 2027. The quantity of zero 
 
 
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1    emission credits to be procured under the contracts shall 
2    be all of the zero emission credits generated by the zero 
3    emission facility in each delivery year; however, if the 
4    zero emission facility is owned by more than one entity, 
5    then the quantity of zero emission credits to be procured 
6    under the contracts shall be the amount of zero emission 
7    credits that are generated from the portion of the zero 
8    emission facility that is owned by the winning supplier.
9        The 16% value identified in this paragraph (1) is the 
10    average of the percentage targets in subparagraph (B) of 
11    paragraph (1) of subsection (c) of this Section for the 5 
12    delivery years beginning June 1, 2017.
13        The procurement process shall be subject to the 
14    following provisions:
15            (A) Those zero emission facilities that intend to 
16        participate in the procurement shall submit to the 
17        Agency the following eligibility information for each 
18        zero emission facility on or before the date 
19        established by the Agency:
20                (i) the in-service date and remaining useful 
21            life of the zero emission facility;
22                (ii) the amount of power generated annually 
23            for each of the years 2005 through 2015, and the 
24            projected zero emission credits to be generated 
25            over the remaining useful life of the zero 
26            emission facility, which shall be used to 
 
 
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1            determine the capability of each facility;
2                (iii) the annual zero emission facility cost 
3            projections, expressed on a per megawatthour 
4            basis, over the next 6 delivery years, which shall 
5            include the following: operation and maintenance 
6            expenses; fully allocated overhead costs, which 
7            shall be allocated using the methodology developed 
8            by the Institute for Nuclear Power Operations; 
9            fuel expenditures; non-fuel capital expenditures; 
10            spent fuel expenditures; a return on working 
11            capital; the cost of operational and market risks 
12            that could be avoided by ceasing operation; and 
13            any other costs necessary for continued 
14            operations, provided that "necessary" means, for 
15            purposes of this item (iii), that the costs could 
16            reasonably be avoided only by ceasing operations 
17            of the zero emission facility; and
18                (iv) a commitment to continue operating, for 
19            the duration of the contract or contracts executed 
20            under the procurement held under this subsection 
21            (d-5), the zero emission facility that produces 
22            the zero emission credits to be procured in the 
23            procurement.
24            The information described in item (iii) of this 
25        subparagraph (A) may be submitted on a confidential 
26        basis and shall be treated and maintained by the 
 
 
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1        Agency, the procurement administrator, and the 
2        Commission as confidential and proprietary and exempt 
3        from disclosure under subparagraphs (a) and (g) of 
4        paragraph (1) of Section 7 of the Freedom of 
5        Information Act. The Office of Attorney General shall 
6        have access to, and maintain the confidentiality of, 
7        such information pursuant to Section 6.5 of the 
8        Attorney General Act. 
9            (B) The price for each zero emission credit 
10        procured under this subsection (d-5) for each delivery 
11        year shall be in an amount that equals the Social Cost 
12        of Carbon, expressed on a price per megawatthour 
13        basis. However, to ensure that the procurement remains 
14        affordable to retail customers in this State if 
15        electricity prices increase, the price in an 
16        applicable delivery year shall be reduced below the 
17        Social Cost of Carbon by the amount ("Price 
18        Adjustment") by which the market price index for the 
19        applicable delivery year exceeds the baseline market 
20        price index for the consecutive 12-month period ending 
21        May 31, 2016. If the Price Adjustment is greater than 
22        or equal to the Social Cost of Carbon in an applicable 
23        delivery year, then no payments shall be due in that 
24        delivery year. The components of this calculation are 
25        defined as follows:
26                (i) Social Cost of Carbon: The Social Cost of 
 
 
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1            Carbon is $16.50 per megawatthour, which is based 
2            on the U.S. Interagency Working Group on Social 
3            Cost of Carbon's price in the August 2016 
4            Technical Update using a 3% discount rate, 
5            adjusted for inflation for each year of the 
6            program. Beginning with the delivery year 
7            commencing June 1, 2023, the price per 
8            megawatthour shall increase by $1 per 
9            megawatthour, and continue to increase by an 
10            additional $1 per megawatthour each delivery year 
11            thereafter.
12                (ii) Baseline market price index: The baseline 
13            market price index for the consecutive 12-month 
14            period ending May 31, 2016 is $31.40 per 
15            megawatthour, which is based on the sum of (aa) 
16            the average day-ahead energy price across all 
17            hours of such 12-month period at the PJM 
18            Interconnection LLC Northern Illinois Hub, (bb) 
19            50% multiplied by the Base Residual Auction, or 
20            its successor, capacity price for the rest of the 
21            RTO zone group determined by PJM Interconnection 
22            LLC, divided by 24 hours per day, and (cc) 50% 
23            multiplied by the Planning Resource Auction, or 
24            its successor, capacity price for Zone 4 
25            determined by the Midcontinent Independent System 
26            Operator, Inc., divided by 24 hours per day. 
 
 
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1                (iii) Market price index: The market price 
2            index for a delivery year shall be the sum of 
3            projected energy prices and projected capacity 
4            prices determined as follows:
5                    (aa) Projected energy prices: the 
6                projected energy prices for the applicable 
7                delivery year shall be calculated once for the 
8                year using the forward market price for the 
9                PJM Interconnection, LLC Northern Illinois 
10                Hub. The forward market price shall be 
11                calculated as follows: the energy forward 
12                prices for each month of the applicable 
13                delivery year averaged for each trade date 
14                during the calendar year immediately preceding 
15                that delivery year to produce a single energy 
16                forward price for the delivery year. The 
17                forward market price calculation shall use 
18                data published by the Intercontinental 
19                Exchange, or its successor.
20                    (bb) Projected capacity prices:
21                        (I) For the delivery years commencing 
22                    June 1, 2017, June 1, 2018, and June 1, 
23                    2019, the projected capacity price shall 
24                    be equal to the sum of (1) 50% multiplied 
25                    by the Base Residual Auction, or its 
26                    successor, price for the rest of the RTO 
 
 
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1                    zone group as determined by PJM 
2                    Interconnection LLC, divided by 24 hours 
3                    per day and, (2) 50% multiplied by the 
4                    resource auction price determined in the 
5                    resource auction administered by the 
6                    Midcontinent Independent System Operator, 
7                    Inc., in which the largest percentage of 
8                    load cleared for Local Resource Zone 4, 
9                    divided by 24 hours per day, and where 
10                    such price is determined by the 
11                    Midcontinent Independent System Operator, 
12                    Inc.
13                        (II) For the delivery year commencing 
14                    June 1, 2020, and each year thereafter, 
15                    the projected capacity price shall be 
16                    equal to the sum of (1) 50% multiplied by 
17                    the Base Residual Auction, or its 
18                    successor, price for the ComEd zone as 
19                    determined by PJM Interconnection LLC, 
20                    divided by 24 hours per day, and (2) 50% 
21                    multiplied by the resource auction price 
22                    determined in the resource auction 
23                    administered by the Midcontinent 
24                    Independent System Operator, Inc., in 
25                    which the largest percentage of load 
26                    cleared for Local Resource Zone 4, divided 
 
 
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1                    by 24 hours per day, and where such price 
2                    is determined by the Midcontinent 
3                    Independent System Operator, Inc.
4            For purposes of this subsection (d-5):
5                "Rest of the RTO" and "ComEd Zone" shall have 
6            the meaning ascribed to them by PJM 
7            Interconnection, LLC. 
8                "RTO" means regional transmission 
9            organization. 
10            (C) No later than 45 days after June 1, 2017 (the 
11        effective date of Public Act 99-906), the Agency shall 
12        publish its proposed zero emission standard 
13        procurement plan. The plan shall be consistent with 
14        the provisions of this paragraph (1) and shall provide 
15        that winning bids shall be selected based on public 
16        interest criteria that include, but are not limited 
17        to, minimizing carbon dioxide emissions that result 
18        from electricity consumed in Illinois and minimizing 
19        sulfur dioxide, nitrogen oxide, and particulate matter 
20        emissions that adversely affect the citizens of this 
21        State. In particular, the selection of winning bids 
22        shall take into account the incremental environmental 
23        benefits resulting from the procurement, such as any 
24        existing environmental benefits that are preserved by 
25        the procurements held under Public Act 99-906 and 
26        would cease to exist if the procurements were not 
 
 
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1        held, including the preservation of zero emission 
2        facilities. The plan shall also describe in detail how 
3        each public interest factor shall be considered and 
4        weighted in the bid selection process to ensure that 
5        the public interest criteria are applied to the 
6        procurement and given full effect.
7            For purposes of developing the plan, the Agency 
8        shall consider any reports issued by a State agency, 
9        board, or commission under House Resolution 1146 of 
10        the 98th General Assembly and paragraph (4) of 
11        subsection (d) of this Section, as well as publicly 
12        available analyses and studies performed by or for 
13        regional transmission organizations that serve the 
14        State and their independent market monitors.
15            Upon publishing of the zero emission standard 
16        procurement plan, copies of the plan shall be posted 
17        and made publicly available on the Agency's website. 
18        All interested parties shall have 10 days following 
19        the date of posting to provide comment to the Agency on 
20        the plan. All comments shall be posted to the Agency's 
21        website. Following the end of the comment period, but 
22        no more than 60 days later than June 1, 2017 (the 
23        effective date of Public Act 99-906), the Agency shall 
24        revise the plan as necessary based on the comments 
25        received and file its zero emission standard 
26        procurement plan with the Commission.
 
 
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1            If the Commission determines that the plan will 
2        result in the procurement of cost-effective zero 
3        emission credits, then the Commission shall, after 
4        notice and hearing, but no later than 45 days after the 
5        Agency filed the plan, approve the plan or approve 
6        with modification. For purposes of this subsection 
7        (d-5), "cost effective" means the projected costs of 
8        procuring zero emission credits from zero emission 
9        facilities do not cause the limit stated in paragraph 
10        (2) of this subsection to be exceeded.
11            (C-5) As part of the Commission's review and 
12        acceptance or rejection of the procurement results, 
13        the Commission shall, in its public notice of 
14        successful bidders:
15                (i) identify how the winning bids satisfy the 
16            public interest criteria described in subparagraph 
17            (C) of this paragraph (1) of minimizing carbon 
18            dioxide emissions that result from electricity 
19            consumed in Illinois and minimizing sulfur 
20            dioxide, nitrogen oxide, and particulate matter 
21            emissions that adversely affect the citizens of 
22            this State;
23                (ii) specifically address how the selection of 
24            winning bids takes into account the incremental 
25            environmental benefits resulting from the 
26            procurement, including any existing environmental 
 
 
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1            benefits that are preserved by the procurements 
2            held under Public Act 99-906 and would have ceased 
3            to exist if the procurements had not been held, 
4            such as the preservation of zero emission 
5            facilities;
6                (iii) quantify the environmental benefit of 
7            preserving the resources identified in item (ii) 
8            of this subparagraph (C-5), including the 
9            following:
10                    (aa) the value of avoided greenhouse gas 
11                emissions measured as the product of the zero 
12                emission facilities' output over the contract 
13                term multiplied by the U.S. Environmental 
14                Protection Agency eGrid subregion carbon 
15                dioxide emission rate and the U.S. Interagency 
16                Working Group on Social Cost of Carbon's price 
17                in the August 2016 Technical Update using a 3% 
18                discount rate, adjusted for inflation for each 
19                delivery year; and
20                    (bb) the costs of replacement with other 
21                zero carbon dioxide resources, including wind 
22                and photovoltaic, based upon the simple 
23                average of the following:
24                        (I) the price, or if there is more 
25                    than one price, the average of the prices, 
26                    paid for renewable energy credits from new 
 
 
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1                    utility-scale wind projects in the 
2                    procurement events specified in item (i) 
3                    of subparagraph (G) of paragraph (1) of 
4                    subsection (c) of this Section; and
5                        (II) the price, or if there is more 
6                    than one price, the average of the prices, 
7                    paid for renewable energy credits from new 
8                    utility-scale solar projects and 
9                    brownfield site photovoltaic projects in 
10                    the procurement events specified in item 
11                    (ii) of subparagraph (G) of paragraph (1) 
12                    of subsection (c) of this Section and, 
13                    after January 1, 2015, renewable energy 
14                    credits from photovoltaic distributed 
15                    generation projects in procurement events 
16                    held under subsection (c) of this Section. 
17            Each utility shall enter into binding contractual 
18        arrangements with the winning suppliers.
19            The procurement described in this subsection 
20        (d-5), including, but not limited to, the execution of 
21        all contracts procured, shall be completed no later 
22        than May 10, 2017. Based on the effective date of 
23        Public Act 99-906, the Agency and Commission may, as 
24        appropriate, modify the various dates and timelines 
25        under this subparagraph and subparagraphs (C) and (D) 
26        of this paragraph (1). The procurement and plan 
 
 
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1        approval processes required by this subsection (d-5) 
2        shall be conducted in conjunction with the procurement 
3        and plan approval processes required by subsection (c) 
4        of this Section and Section 16-111.5 of the Public 
5        Utilities Act, to the extent practicable. 
6        Notwithstanding whether a procurement event is 
7        conducted under Section 16-111.5 of the Public 
8        Utilities Act, the Agency shall immediately initiate a 
9        procurement process on June 1, 2017 (the effective 
10        date of Public Act 99-906).
11            (D) Following the procurement event described in 
12        this paragraph (1) and consistent with subparagraph 
13        (B) of this paragraph (1), the Agency shall calculate 
14        the payments to be made under each contract for the 
15        next delivery year based on the market price index for 
16        that delivery year. The Agency shall publish the 
17        payment calculations no later than May 25, 2017 and 
18        every May 25 thereafter.
19            (E) Notwithstanding the requirements of this 
20        subsection (d-5), the contracts executed under this 
21        subsection (d-5) shall provide that the zero emission 
22        facility may, as applicable, suspend or terminate 
23        performance under the contracts in the following 
24        instances:
25                (i) A zero emission facility shall be excused 
26            from its performance under the contract for any 
 
 
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1            cause beyond the control of the resource, 
2            including, but not restricted to, acts of God, 
3            flood, drought, earthquake, storm, fire, 
4            lightning, epidemic, war, riot, civil disturbance 
5            or disobedience, labor dispute, labor or material 
6            shortage, sabotage, acts of public enemy, 
7            explosions, orders, regulations or restrictions 
8            imposed by governmental, military, or lawfully 
9            established civilian authorities, which, in any of 
10            the foregoing cases, by exercise of commercially 
11            reasonable efforts the zero emission facility 
12            could not reasonably have been expected to avoid, 
13            and which, by the exercise of commercially 
14            reasonable efforts, it has been unable to 
15            overcome. In such event, the zero emission 
16            facility shall be excused from performance for the 
17            duration of the event, including, but not limited 
18            to, delivery of zero emission credits, and no 
19            payment shall be due to the zero emission facility 
20            during the duration of the event.
21                (ii) A zero emission facility shall be 
22            permitted to terminate the contract if legislation 
23            is enacted into law by the General Assembly that 
24            imposes or authorizes a new tax, special 
25            assessment, or fee on the generation of 
26            electricity, the ownership or leasehold of a 
 
 
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1            generating unit, or the privilege or occupation of 
2            such generation, ownership, or leasehold of 
3            generation units by a zero emission facility. 
4            However, the provisions of this item (ii) do not 
5            apply to any generally applicable tax, special 
6            assessment or fee, or requirements imposed by 
7            federal law.
8                (iii) A zero emission facility shall be 
9            permitted to terminate the contract in the event 
10            that the resource requires capital expenditures in 
11            excess of $40,000,000 that were neither known nor 
12            reasonably foreseeable at the time it executed the 
13            contract and that a prudent owner or operator of 
14            such resource would not undertake.
15                (iv) A zero emission facility shall be 
16            permitted to terminate the contract in the event 
17            the Nuclear Regulatory Commission terminates the 
18            resource's license.
19            (F) If the zero emission facility elects to 
20        terminate a contract under subparagraph (E) of this 
21        paragraph (1), then the Commission shall reopen the 
22        docket in which the Commission approved the zero 
23        emission standard procurement plan under subparagraph 
24        (C) of this paragraph (1) and, after notice and 
25        hearing, enter an order acknowledging the contract 
26        termination election if such termination is consistent 
 
 
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1        with the provisions of this subsection (d-5).
2        (2) For purposes of this subsection (d-5), the amount 
3    paid per kilowatthour means the total amount paid for 
4    electric service expressed on a per kilowatthour basis. 
5    For purposes of this subsection (d-5), the total amount 
6    paid for electric service includes, without limitation, 
7    amounts paid for supply, transmission, distribution, 
8    surcharges, and add-on taxes.
9        Notwithstanding the requirements of this subsection 
10    (d-5), the contracts executed under this subsection (d-5) 
11    shall provide that the total of zero emission credits 
12    procured under a procurement plan shall be subject to the 
13    limitations of this paragraph (2). For each delivery year, 
14    the contractual volume receiving payments in such year 
15    shall be reduced for all retail customers based on the 
16    amount necessary to limit the net increase that delivery 
17    year to the costs of those credits included in the amounts 
18    paid by eligible retail customers in connection with 
19    electric service to no more than 1.65% of the amount paid 
20    per kilowatthour by eligible retail customers during the 
21    year ending May 31, 2009. The result of this computation 
22    shall apply to and reduce the procurement for all retail 
23    customers, and all those customers shall pay the same 
24    single, uniform cents per kilowatthour charge under 
25    subsection (k) of Section 16-108 of the Public Utilities 
26    Act. To arrive at a maximum dollar amount of zero emission 
 
 
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1    credits to be paid for the particular delivery year, the 
2    resulting per kilowatthour amount shall be applied to the 
3    actual amount of kilowatthours of electricity delivered by 
4    the electric utility in the delivery year immediately 
5    prior to the procurement, to all retail customers in its 
6    service territory. Unpaid contractual volume for any 
7    delivery year shall be paid in any subsequent delivery 
8    year in which such payments can be made without exceeding 
9    the amount specified in this paragraph (2). The 
10    calculations required by this paragraph (2) shall be made 
11    only once for each procurement plan year. Once the 
12    determination as to the amount of zero emission credits to 
13    be paid is made based on the calculations set forth in this 
14    paragraph (2), no subsequent rate impact determinations 
15    shall be made and no adjustments to those contract amounts 
16    shall be allowed. All costs incurred under those contracts 
17    and in implementing this subsection (d-5) shall be 
18    recovered by the electric utility as provided in this 
19    Section.
20        No later than June 30, 2019, the Commission shall 
21    review the limitation on the amount of zero emission 
22    credits procured under this subsection (d-5) and report to 
23    the General Assembly its findings as to whether that 
24    limitation unduly constrains the procurement of 
25    cost-effective zero emission credits. 
26        (3) Six years after the execution of a contract under 
 
 
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1    this subsection (d-5), the Agency shall determine whether 
2    the actual zero emission credit payments received by the 
3    supplier over the 6-year period exceed the Average ZEC 
4    Payment. In addition, at the end of the term of a contract 
5    executed under this subsection (d-5), or at the time, if 
6    any, a zero emission facility's contract is terminated 
7    under subparagraph (E) of paragraph (1) of this subsection 
8    (d-5), then the Agency shall determine whether the actual 
9    zero emission credit payments received by the supplier 
10    over the term of the contract exceed the Average ZEC 
11    Payment, after taking into account any amounts previously 
12    credited back to the utility under this paragraph (3). If 
13    the Agency determines that the actual zero emission credit 
14    payments received by the supplier over the relevant period 
15    exceed the Average ZEC Payment, then the supplier shall 
16    credit the difference back to the utility. The amount of 
17    the credit shall be remitted to the applicable electric 
18    utility no later than 120 days after the Agency's 
19    determination, which the utility shall reflect as a credit 
20    on its retail customer bills as soon as practicable; 
21    however, the credit remitted to the utility shall not 
22    exceed the total amount of payments received by the 
23    facility under its contract.
24        For purposes of this Section, the Average ZEC Payment 
25    shall be calculated by multiplying the quantity of zero 
26    emission credits delivered under the contract times the 
 
 
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1    average contract price. The average contract price shall 
2    be determined by subtracting the amount calculated under 
3    subparagraph (B) of this paragraph (3) from the amount 
4    calculated under subparagraph (A) of this paragraph (3), 
5    as follows:
6            (A) The average of the Social Cost of Carbon, as 
7        defined in subparagraph (B) of paragraph (1) of this 
8        subsection (d-5), during the term of the contract.
9            (B) The average of the market price indices, as 
10        defined in subparagraph (B) of paragraph (1) of this 
11        subsection (d-5), during the term of the contract, 
12        minus the baseline market price index, as defined in 
13        subparagraph (B) of paragraph (1) of this subsection 
14        (d-5).
15        If the subtraction yields a negative number, then the 
16    Average ZEC Payment shall be zero. 
17        (4) Cost-effective zero emission credits procured from 
18    zero emission facilities shall satisfy the applicable 
19    definitions set forth in Section 1-10 of this Act.
20        (5) The electric utility shall retire all zero 
21    emission credits used to comply with the requirements of 
22    this subsection (d-5).
23        (6) Electric utilities shall be entitled to recover 
24    all of the costs associated with the procurement of zero 
25    emission credits through an automatic adjustment clause 
26    tariff in accordance with subsection (k) and (m) of 
 
 
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1    Section 16-108 of the Public Utilities Act, and the 
2    contracts executed under this subsection (d-5) shall 
3    provide that the utilities' payment obligations under such 
4    contracts shall be reduced if an adjustment is required 
5    under subsection (m) of Section 16-108 of the Public 
6    Utilities Act.
7        (7) This subsection (d-5) shall become inoperative on 
8    January 1, 2028. 
9    (d-10) Nuclear Plant Assistance; carbon mitigation 
10credits.
11    (1) The General Assembly finds:
12        (A) The health, welfare, and prosperity of all 
13    Illinois citizens require that the State of Illinois act 
14    to avoid and not increase carbon emissions from electric 
15    generation sources while continuing to ensure affordable, 
16    stable, and reliable electricity to all citizens.
17        (B) Absent immediate action by the State to preserve 
18    existing carbon-free energy resources, those resources may 
19    retire, and the electric generation needs of Illinois' 
20    retail customers may be met instead by facilities that 
21    emit significant amounts of carbon pollution and other 
22    harmful air pollutants at a high social and economic cost 
23    until Illinois is able to develop other forms of clean 
24    energy.
25        (C) The General Assembly finds that nuclear power 
26    generation is necessary for the State's transition to 100% 
 
 
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1    clean energy, and ensuring continued operation of nuclear 
2    plants advances environmental and public health interests 
3    through providing carbon-free electricity while reducing 
4    the air pollution profile of the Illinois energy 
5    generation fleet.
6        (D) The clean energy attributes of nuclear generation 
7    facilities support the State in its efforts to achieve 
8    100% clean energy.
9        (E) The State currently invests in various forms of 
10    clean energy, including, but not limited to, renewable 
11    energy, energy efficiency, and low-emission vehicles, 
12    among others.
13        (F) The Environmental Protection Agency commissioned 
14    an independent audit which provided a detailed assessment 
15    of the financial condition of the Illinois nuclear fleet 
16    to evaluate its financial viability and whether the 
17    environmental benefits of such resources were at risk. The 
18    report identified the risk of losing the environmental 
19    benefits of several specific nuclear units. The report 
20    also identified that the LaSalle County Generating Station 
21    will continue to operate through 2026 and therefore is not 
22    eligible to participate in the carbon mitigation credit 
23    program.
24        (G) Nuclear plants provide carbon-free energy, which 
25    helps to avoid many health-related negative impacts for 
26    Illinois residents.
 
 
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1        (H) The procurement of carbon mitigation credits 
2    representing the environmental benefits of carbon-free 
3    generation will further the State's efforts at achieving 
4    100% clean energy and decarbonizing the electricity sector 
5    in a safe, reliable, and affordable manner. Further, the 
6    procurement of carbon emission credits will enhance the 
7    health and welfare of Illinois residents through decreased 
8    reliance on more highly polluting generation.
9        (I) The General Assembly therefore finds it necessary 
10    to establish carbon mitigation credits to ensure decreased 
11    reliance on more carbon-intensive energy resources, for 
12    transitioning to a fully decarbonized electricity sector, 
13    and to help ensure health and welfare of the State's 
14    residents.
15    (2) As used in this subsection:
16    "Baseline costs" means costs used to establish a customer 
17protection cap that have been evaluated through an independent 
18audit of a carbon-free energy resource conducted by the 
19Environmental Protection Agency that evaluated projected 
20annual costs for operation and maintenance expenses; fully 
21allocated overhead costs, which shall be allocated using the 
22methodology developed by the Institute for Nuclear Power 
23Operations; fuel expenditures; nonfuel capital expenditures; 
24spent fuel expenditures; a return on working capital; the cost 
25of operational and market risks that could be avoided by 
26ceasing operation; and any other costs necessary for continued 
 
 
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1operations, provided that "necessary" means, for purposes of 
2this definition, that the costs could reasonably be avoided 
3only by ceasing operations of the carbon-free energy resource.
4    "Carbon mitigation credit" means a tradable credit that 
5represents the carbon emission reduction attributes of one 
6megawatt-hour of energy produced from a carbon-free energy 
7resource.
8    "Carbon-free energy resource" means a generation facility 
9that: (1) is fueled by nuclear power; and (2) is 
10interconnected to PJM Interconnection, LLC.
11    (3) Procurement.
12        (A) Beginning with the delivery year commencing on 
13    June 1, 2022, the Agency shall, for electric utilities 
14    serving at least 3,000,000 retail customers in the State, 
15    seek to procure contracts for no more than approximately 
16    54,500,000 cost-effective carbon mitigation credits from 
17    carbon-free energy resources because such credits are 
18    necessary to support current levels of carbon-free energy 
19    generation and ensure the State meets its carbon dioxide 
20    emissions reduction goals. The Agency shall not make a 
21    partial award of a contract for carbon mitigation credits 
22    covering a fractional amount of a carbon-free energy 
23    resource's projected output.
24        (B) Each carbon-free energy resource that intends to 
25    participate in a procurement shall be required to submit 
26    to the Agency the following information for the resource 
 
 
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1    on or before the date established by the Agency:
2            (i) the in-service date and remaining useful life 
3        of the carbon-free energy resource;
4            (ii) the amount of power generated annually for 
5        each of the past 10 years, which shall be used to 
6        determine the capability of each facility;
7            (iii) a commitment to be reflected in any contract 
8        entered into pursuant to this subsection (d-10) to 
9        continue operating the carbon-free energy resource at 
10        a capacity factor of at least 88% annually on average 
11        for the duration of the contract or contracts executed 
12        under the procurement held under this subsection 
13        (d-10), except in an instance described in 
14        subparagraph (E) of paragraph (1) of subsection (d-5) 
15        of this Section or made impracticable as a result of 
16        compliance with law or regulation;
17            (iv) financial need and the risk of loss of the 
18        environmental benefits of such resource, which shall 
19        include the following information:
20                (I) the carbon-free energy resource's cost 
21            projections, expressed on a per megawatt-hour 
22            basis, over the next 5 delivery years, which shall 
23            include the following: operation and maintenance 
24            expenses; fully allocated overhead costs, which 
25            shall be allocated using the methodology developed 
26            by the Institute for Nuclear Power Operations; 
 
 
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1            fuel expenditures; nonfuel capital expenditures; 
2            spent fuel expenditures; a return on working 
3            capital; the cost of operational and market risks 
4            that could be avoided by ceasing operation; and 
5            any other costs necessary for continued 
6            operations, provided that "necessary" means, for 
7            purposes of this subitem (I), that the costs could 
8            reasonably be avoided only by ceasing operations 
9            of the carbon-free energy resource; and
10                (II) the carbon-free energy resource's revenue 
11            projections, including energy, capacity, ancillary 
12            services, any other direct State support, known or 
13            anticipated federal attribute credits, known or 
14            anticipated tax credits, and any other direct 
15            federal support.
16        The information described in this subparagraph (B) may 
17    be submitted on a confidential basis and shall be treated 
18    and maintained by the Agency, the procurement 
19    administrator, and the Commission as confidential and 
20    proprietary and exempt from disclosure under subparagraphs 
21    (a) and (g) of paragraph (1) of Section 7 of the Freedom of 
22    Information Act. The Office of the Attorney General shall 
23    have access to, and maintain the confidentiality of, such 
24    information pursuant to Section 6.5 of the Attorney 
25    General Act. 
26        (C) The Agency shall solicit bids for the contracts 
 
 
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1    described in this subsection (d-10) from carbon-free 
2    energy resources that have satisfied the requirements of 
3    subparagraph (B) of this paragraph (3). The contracts 
4    procured pursuant to a procurement event shall reflect, 
5    and be subject to, the following terms, requirements, and 
6    limitations:
7            (i) Contracts are for delivery of carbon 
8        mitigation credits, and are not energy or capacity 
9        sales contracts requiring physical delivery. Pursuant 
10        to item (iii), contract payments shall fully deduct 
11        the value of any monetized federal production tax 
12        credits, credits issued pursuant to a federal clean 
13        energy standard, and other federal credits if 
14        applicable.
15            (ii) Contracts for carbon mitigation credits shall 
16        commence with the delivery year beginning on June 1, 
17        2022 and shall be for a term of 5 delivery years 
18        concluding on May 31, 2027.
19            (iii) The price per carbon mitigation credit to be 
20        paid under a contract for a given delivery year shall 
21        be equal to an accepted bid price less the sum of:
22                (I) one of the following energy price indices, 
23            selected by the bidder at the time of the bid for 
24            the term of the contract:
25                    (aa) the weighted-average hourly day-ahead 
26                price for the applicable delivery year at the 
 
 
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1                busbar of all resources procured pursuant to 
2                this subsection (d-10), weighted by actual 
3                production from the resources; or
4                    (bb) the projected energy price for the 
5                PJM Interconnection, LLC Northern Illinois Hub 
6                for the applicable delivery year determined 
7                according to subitem (aa) of item (iii) of 
8                subparagraph (B) of paragraph (1) of 
9                subsection (d-5).
10                (II) the Base Residual Auction Capacity Price 
11            for the ComEd zone as determined by PJM 
12            Interconnection, LLC, divided by 24 hours per day, 
13            for the applicable delivery year for the first 3 
14            delivery years, and then any subsequent delivery 
15            years unless the PJM Interconnection, LLC applies 
16            the Minimum Offer Price Rule to participating 
17            carbon-free energy resources because they supply 
18            carbon mitigation credits pursuant to this Section 
19            at which time, upon notice by the carbon-free 
20            energy resource to the Commission and subject to 
21            the Commission's confirmation, the value under 
22            this subitem shall be zero, as further described 
23            in the carbon mitigation credit procurement plan; 
24            and
25                (III) any value of monetized federal tax 
26            credits, direct payments, or similar subsidy 
 
 
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1            provided to the carbon-free energy resource from 
2            any unit of government that is not already 
3            reflected in energy prices.
4            If the price-per-megawatt-hour calculation 
5        performed under item (iii) of this subparagraph (C) 
6        for a given delivery year results in a net positive 
7        value, then the electric utility counterparty to the 
8        contract shall multiply such net value by the 
9        applicable contract quantity and remit the amount to 
10        the supplier.
11            To protect retail customers from retail rate 
12        impacts that may arise upon the initiation of carbon 
13        policy changes, if the price-per-megawatt-hour 
14        calculation performed under item (iii) of this 
15        subparagraph (C) for a given delivery year results in 
16        a net negative value, then the supplier counterparty 
17        to the contract shall multiply such net value by the 
18        applicable contract quantity and remit such amount to 
19        the electric utility counterparty. The electric 
20        utility shall reflect such amounts remitted by 
21        suppliers as a credit on its retail customer bills as 
22        soon as practicable.
23            (iv) To ensure that retail customers in Northern 
24        Illinois do not pay more for carbon mitigation credits 
25        than the value such credits provide, and 
26        notwithstanding the provisions of this subsection 
 
 
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1        (d-10), the Agency shall not accept bids for contracts 
2        that exceed a customer protection cap equal to the 
3        baseline costs of carbon-free energy resources.
4            The baseline costs for the applicable year shall 
5        be the following:
6                (I) For the delivery year beginning June 1, 
7            2022, the baseline costs shall be an amount equal 
8            to $30.30 per megawatt-hour.
9                (II) For the delivery year beginning June 1, 
10            2023, the baseline costs shall be an amount equal 
11            to $32.50 per megawatt-hour.
12                (III) For the delivery year beginning June 1, 
13            2024, the baseline costs shall be an amount equal 
14            to $33.43 per megawatt-hour.
15                (IV) For the delivery year beginning June 1, 
16            2025, the baseline costs shall be an amount equal 
17            to $33.50 per megawatt-hour.
18                (V) For the delivery year beginning June 1, 
19            2026, the baseline costs shall be an amount equal 
20            to $34.50 per megawatt-hour.
21            An Environmental Protection Agency consultant 
22        forecast, included in a report issued April 14, 2021, 
23        projects that a carbon-free energy resource has the 
24        opportunity to earn on average approximately $30.28 
25        per megawatt-hour, for the sale of energy and capacity 
26        during the time period between 2022 and 2027. 
 
 
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1        Therefore, the sale of carbon mitigation credits 
2        provides the opportunity to receive an additional 
3        amount per megawatt-hour in addition to the projected 
4        prices for energy and capacity.
5            Although actual energy and capacity prices may 
6        vary from year-to-year, the General Assembly finds 
7        that this customer protection cap will help ensure 
8        that the cost of carbon mitigation credits will be 
9        less than its value, based upon the social cost of 
10        carbon identified in the Technical Support Document 
11        issued in February 2021 by the U.S. Interagency 
12        Working Group on Social Cost of Greenhouse Gases and 
13        the PJM Interconnection, LLC carbon dioxide marginal 
14        emission rate for 2020, and that a carbon-free energy 
15        resource receiving payment for carbon mitigation 
16        credits receives no more than necessary to keep those 
17        units in operation.
18        (D) No later than 7 days after the effective date of 
19    this amendatory Act of the 102nd General Assembly, the 
20    Agency shall publish its proposed carbon mitigation credit 
21    procurement plan. The Plan shall provide that winning bids 
22    shall be selected by taking into consideration which 
23    resources best match public interest criteria that 
24    include, but are not limited to, minimizing carbon dioxide 
25    emissions that result from electricity consumed in 
26    Illinois and minimizing sulfur dioxide, nitrogen oxide, 
 
 
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1    and particulate matter emissions that adversely affect the 
2    citizens of this State. The selection of winning bids 
3    shall also take into account the incremental environmental 
4    benefits resulting from the procurement or procurements, 
5    such as any existing environmental benefits that are 
6    preserved by a procurement held under this subsection 
7    (d-10) and would cease to exist if the procurement were 
8    not held, including the preservation of carbon-free energy 
9    resources. For those bidders having the same public 
10    interest criteria score, the relative ranking of such 
11    bidders shall be determined by price. The Plan shall 
12    describe in detail how each public interest factor shall 
13    be considered and weighted in the bid selection process to 
14    ensure that the public interest criteria are applied to 
15    the procurement. The Plan shall, to the extent practical 
16    and permissible by federal law, ensure that successful 
17    bidders make commercially reasonable efforts to apply for 
18    federal tax credits, direct payments, or similar subsidy 
19    programs that support carbon-free generation and for which 
20    the successful bidder is eligible. Upon publishing of the 
21    carbon mitigation credit procurement plan, copies of the 
22    plan shall be posted and made publicly available on the 
23    Agency's website. All interested parties shall have 7 days 
24    following the date of posting to provide comment to the 
25    Agency on the plan. All comments shall be posted to the 
26    Agency's website. Following the end of the comment period, 
 
 
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1    but no more than 19 days later than the effective date of 
2    this amendatory Act of the 102nd General Assembly, the 
3    Agency shall revise the plan as necessary based on the 
4    comments received and file its carbon mitigation credit 
5    procurement plan with the Commission.
6        (E) If the Commission determines that the plan is 
7    likely to result in the procurement of cost-effective 
8    carbon mitigation credits, then the Commission shall, 
9    after notice and hearing and opportunity for comment, but 
10    no later than 42 days after the Agency filed the plan, 
11    approve the plan or approve it with modification. For 
12    purposes of this subsection (d-10), "cost-effective" means 
13    carbon mitigation credits that are procured from 
14    carbon-free energy resources at prices that are within the 
15    limits specified in this paragraph (3). As part of the 
16    Commission's review and acceptance or rejection of the 
17    procurement results, the Commission shall, in its public 
18    notice of successful bidders:
19            (i) identify how the selected carbon-free energy 
20        resources satisfy the public interest criteria 
21        described in this paragraph (3) of minimizing carbon 
22        dioxide emissions that result from electricity 
23        consumed in Illinois and minimizing sulfur dioxide, 
24        nitrogen oxide, and particulate matter emissions that 
25        adversely affect the citizens of this State;
26            (ii) specifically address how the selection of 
 
 
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1        carbon-free energy resources takes into account the 
2        incremental environmental benefits resulting from the 
3        procurement, including any existing environmental 
4        benefits that are preserved by the procurements held 
5        under this amendatory Act of the 102nd General 
6        Assembly and would have ceased to exist if the 
7        procurements had not been held, such as the 
8        preservation of carbon-free energy resources;
9            (iii) quantify the environmental benefit of 
10        preserving the carbon-free energy resources procured 
11        pursuant to this subsection (d-10), including the 
12        following:
13                (I) an assessment value of avoided greenhouse 
14            gas emissions measured as the product of the 
15            carbon-free energy resources' output over the 
16            contract term, using generally accepted 
17            methodologies for the valuation of avoided 
18            emissions; and
19                (II) an assessment of costs of replacement 
20            with other carbon-free energy resources and 
21            renewable energy resources, including wind and 
22            photovoltaic generation, based upon an assessment 
23            of the prices paid for renewable energy credits 
24            through programs and procurements conducted 
25            pursuant to subsection (c) of Section 1-75 of this 
26            Act, and the additional storage necessary to 
 
 
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1            produce the same or similar capability of matching 
2            customer usage patterns.
3        (F) The procurements described in this paragraph (3), 
4    including, but not limited to, the execution of all 
5    contracts procured, shall be completed no later than 
6    December 3, 2021. The procurement and plan approval 
7    processes required by this paragraph (3) shall be 
8    conducted in conjunction with the procurement and plan 
9    approval processes required by Section 16-111.5 of the 
10    Public Utilities Act, to the extent practicable. However, 
11    the Agency and Commission may, as appropriate, modify the 
12    various dates and timelines under this subparagraph and 
13    subparagraphs (D) and (E) of this paragraph (3) to meet 
14    the December 3, 2021 contract execution deadline. 
15    Following the completion of such procurements, and 
16    consistent with this paragraph (3), the Agency shall 
17    calculate the payments to be made under each contract in a 
18    timely fashion.
19        (F-1) Costs incurred by the electric utility pursuant 
20    to a contract authorized by this subsection (d-10) shall 
21    be deemed prudently incurred and reasonable in amount, and 
22    the electric utility shall be entitled to full cost 
23    recovery pursuant to a tariff or tariffs filed with the 
24    Commission.
25        (G) The counterparty electric utility shall retire all 
26    carbon mitigation credits used to comply with the 
 
 
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1    requirements of this subsection (d-10).
2        (H) If a carbon-free energy resource is sold to 
3    another owner, the rights, obligations, and commitments 
4    under this subsection (d-10) shall continue to the 
5    subsequent owner.
6        (I) This subsection (d-10) shall become inoperative on 
7    January 1, 2028.
8    (d-20) Energy storage system portfolio standard.
9        (1) The General Assembly finds that the deployment of 
10    energy storage systems is necessary to successfully 
11    integrate high levels of renewable energy, to avoid the 
12    creation and increase of carbon emissions from electric 
13    generation sources, and to ensure affordable, stable, 
14    clean, reliable, and resilient electricity.
15        (2) The Agency shall develop an energy storage system 
16    resources procurement plan that includes the competitive 
17    procurement events, procurement programs, or both, as 
18    necessary (i) to meet the goals set forth in this 
19    subsection (d-20), (ii) to meet the planning requirements 
20    established under Sections 16-201 and 16-202 of the Public 
21    Utilities Act, (iii) to meet the clean energy policy 
22    established by Public Act 102-662, and (iv) to cause 
23    electric utilities serving more than 300,000 customers in 
24    the State as of January 1, 2019 to contract for energy 
25    storage resources. The energy storage system resources 
26    procurement plan approval processes shall be conducted 
 
 
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1    consistent with the processes outlined in paragraph (6) of 
2    subsection (b) of Section 16-111.5 of the Public Utilities 
3    Act, with the initial energy storage system resources 
4    procurement plan released for comment in calendar year 
5    2027. The Agency shall review and may revise the energy 
6    storage system resources procurement plan at least every 2 
7    years. The Agency shall establish, and the Commission 
8    shall approve or approve as modified, an energy storage 
9    system resources procurement plan that includes:
10            (A) storage targets in addition to the initial 
11        procurements specified in paragraph (3) of this 
12        subsection (d-20) at levels identified through the 
13        integrated resource planning process outlined in 
14        Section 16-202 of the Public Utilities Act;
15            (B) a bid selection process that is based on the 
16        bid price, when compared with an equal energy storage 
17        duration and interconnected to the same independent 
18        system operator (ISO) or regional transmission 
19        organization (RTO), and that may provide for 
20        consideration of the following:
21                (i) the project's viability and ability to 
22            meet or exceed operational date targets;
23                (ii) the developer's experience;
24                (iii) requirements for demonstration of 
25            binding site control that are sufficient for 
26            proposed energy storage facilities;
 
 
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1                (iv) the availability or dependence on any 
2            transmission expansion or upgrades needed; and
3                (v) other resource adequacy and reliability 
4            considerations;
5            (C) consideration of the need to ensure adequate, 
6        reliable, affordable, efficient, and environmentally 
7        sustainable electric service at the lowest total cost 
8        over time;
9            (D) proposals for the financial support of energy 
10        storage systems using contract models, which may 
11        include, but are not limited to, the following:
12                (i) an indexed storage credit procurement, 
13            including payments to energy storage system owners 
14            or operators with any offsets and refunds for 
15            potential energy and capacity revenues;
16                (ii) support for energy storage system 
17            resources through contract structures that do not 
18            create contractual obligations on utilities that 
19            are not contingent on full and timely cost 
20            recovery, that avoid negative financial impacts on 
21            the utilities, and that are agreed upon by the 
22            utilities; and
23                (iii) other approaches as deemed suitable by 
24            the Agency and the Commission; and
25            (E) consideration that the Agency may include a 
26        methodology that could prioritize procurement of 
 
 
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1        energy storage resources that are located in 
2        communities eligible to receive Energy Transition 
3        Community Grants pursuant to Section 10-20 of the 
4        Energy Community Reinvestment Act.    
5        In developing its procurement plan and conducting the 
6    storage procurements outlined in this paragraph (2) and in 
7    paragraph (3), the Agency may use the services of expert 
8    consulting firms identified in paragraphs (1) and (2) of 
9    subsection (a) of this Section.
10        (3) Notwithstanding whether an energy storage system 
11    resources procurement plan has been approved, the 
12    following provisions shall apply to the Agency's initial 
13    procurement of energy storage system resources under this 
14    subsection (d-20):
15            (A) The Agency shall conduct an initial energy 
16        storage procurement on or before August 26, 2026 or 90 
17        days after the effective date of this amendatory Act 
18        of the 104th General Assembly, whichever is earlier. 
19        For the purposes of this initial energy storage 
20        procurement, the Agency shall conduct a procurement 
21        that results in electric utilities that served more 
22        than 300,000 customers in the State as of January 1, 
23        2019 contracting for at least 1,038 megawatts of 
24        cost-effective stand-alone energy storage systems that 
25        can achieve commercial operation on or before December 
26        31, 2029 or an alternative date proposed by the Agency 
 
 
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1        that is no later than December 31, 2030. The 
2        procurement target shall be separated for projects 
3        interconnected within Midcontinent Independent System 
4        Operator Local Resource Zone 4 (MISO Zone 4) and for 
5        projects interconnected within the PJM 
6        Interconnection, LLC ComEd Locational Deliverability 
7        Area (PJM ComEd Area) as follows:
8                (i) 450 megawatts in MISO Zone 4; and
9                (ii) 588 megawatts in the PJM ComEd Area.
10            For purposes of this subsection (d-20), 
11        "stand-alone" means systems that are (i) separately 
12        metered by a revenue-quality meter that satisfies the 
13        requirements of the RTO; (ii) operate independently 
14        without constraints or hindrances from other 
15        generation units; and (iii) demonstrate the ability to 
16        charge and discharge independent of any generation 
17        unit output.    
18            (B) The Agency shall conduct a series of 
19        additional energy storage procurements that result in 
20        electric utilities contracting for energy storage 
21        resources in an amount of at least 3,000 megawatts of 
22        cumulative energy storage capacity for projects 
23        committed to reaching commercial operation on or 
24        before December 31, 2029, or an alternative date 
25        proposed by the Agency that is no later than December 
26        31, 2030, subject to extension for a delay due to 
 
 
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1        interconnection of the energy storage system, a delay 
2        in obtaining permits necessary to build or operate the 
3        energy storage system, or other circumstances at the 
4        discretion of the Agency and in an amount of at least 
5        6,000 megawatts of cumulative energy storage capacity 
6        for projects committed to reaching commercial 
7        operation on or before December 31, 2034, subject to 
8        extension for a delay due to interconnection of the 
9        energy storage system, a delay in obtaining permits 
10        necessary to build or operate the energy storage 
11        system, or other circumstances at the discretion of 
12        the Agency.
13            The additional energy storage resources 
14        procurements shall be conducted in calendar years 
15        2026, 2027, 2028, and 2029 in a manner that ensures the 
16        quantities listed in this subparagraph (B) are met in 
17        the specified timeframe. The procurements shall be 
18        conducted in a manner that maximizes projects 
19        available in the MISO and PJM queues, ensures the 
20        likelihood of project development through the 
21        development of project maturity requirements, enables 
22        sufficient competition for price competitiveness, and 
23        aligns to the extent practicable with regional 
24        transmission organization study phases. The 
25        procurements shall select projects interconnected to 
26        MISO Zone 4 and the PJM ComEd Area and shall follow 
 
 
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1        either (i) a similar geographic split to the ratio of 
2        quantities established in subparagraph (A) of this 
3        paragraph (3), (ii) an alternative geographic split 
4        proposed by the Agency based on project availability 
5        in advanced stages of the MISO and PJM queues, or (iii) 
6        that is informed by MISO and PJM planning activities, 
7        auctions, or reports that indicate capacity resource 
8        shortages or impending shortages and that reflect the 
9        assessments made through the processes outlined in 
10        subparagraph (A) of paragraph (2). The additional 
11        energy storage capacity procurements may be adjusted 
12        upward if determined necessary through the planning 
13        process outlined in Section 16-201 of the Public 
14        Utilities Act at times determined by the Commission.
15            (C) The initial energy storage resources 
16        procurement under subparagraph (A) of this paragraph 
17        (3) shall adopt a standard indexed storage credit 
18        contract modeled after the contract and follow a 
19        process modeled after the process included in the 
20        staff report submitted to the Governor, General 
21        Assembly, and Commission pursuant to subsection (g) of 
22        Section 16-135 of the Public Utilities Act on May 1, 
23        2025. In developing the procurement rules and 
24        procurement process for the initial procurement, the 
25        Agency shall provide an opportunity for comment on the 
26        indexed storage credit contract included in the May 1, 
 
 
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1        2025 staff report and shall adopt modifications to the 
2        contract consistent with the process outlined in 
3        paragraph (2) of subsection (e) of Section 16-111.5 of 
4        the Public Utilities Act.
5            (D) For the additional energy storage resources 
6        procurements conducted in accordance with subparagraph 
7        (B) of this paragraph (3), the Agency may, among other 
8        considerations, consider other contract structures if 
9        such contract structures and agreements do not create 
10        contractual obligations on utilities that are not 
11        contingent on full and timely cost recovery, avoid 
12        negative financial impacts on the utilities, and are 
13        agreed upon by the participating utility.
14            (E) The initial and additional energy storage 
15        resources procurements under this paragraph (3) shall 
16        solicit 20-year contracts.
17            (F) The Agency shall submit its proposed selection 
18        of successful bids for each procurement event pursuant 
19        to paragraphs (2) and (3) to the Commission for 
20        approval consistent with the processes outlined in 
21        Section 16-111.5 of the Public Utilities Act to the 
22        extent practicable.
23        (4) The energy storage system resources procurement 
24    plans developed by the Agency may consider alternatives to 
25    the initial and additional procurement terms described in 
26    paragraph (3) of this subsection (d-20), including, but 
 
 
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1    not limited to:
2            (A) alternatives to the standard indexed storage 
3        credit contract used in the initial terms described in 
4        subparagraph (C) of paragraph (3) of this subsection 
5        (d-20);
6            (B) energy storage systems that are not 
7        stand-alone;
8            (C) proportionate allocations between MISO Zone 4 
9        and the PJM ComEd Area that are not based upon load 
10        share, including allocations reflecting the 
11        assessments made through the processes outlined in 
12        subparagraph (A) of paragraph (2);
13            (D) contract lengths other than 20 years;
14            (E) energy storage system durations other than 4 
15        hours; and
16            (F) energy storage systems connected to the 
17        distribution systems of the electric utilities.
18        The Agency may propose specific timelines for energy 
19    storage system resources procurements, which may differ 
20    across RTO zones, that are based in part upon a 
21    consideration of (i) the timing of the release of 
22    interconnection cost information through both MISO and PJM 
23    interconnection queue processes, (ii) factors that 
24    maximize the likelihood of successful project development, 
25    (iii) enabling sufficient competition for price 
26    competitiveness, and (iv) aligning to the extent 
 
 
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1    practicable with RTO study phases.
2        (5) The Agency shall procure cost-effective energy 
3    storage credits or other contract instruments intended to 
4    facilitate the successful development of energy storage 
5    projects. The procurement administrator shall establish 
6    confidential price benchmarks based on publicly available 
7    data on regional technology costs. Confidential price 
8    benchmarks shall be developed by the procurement 
9    administrator, in consultation with Commission staff, 
10    Agency staff, and the procurement monitor, and shall be 
11    subject to Commission review and approval. Price 
12    benchmarks shall reflect development costs, financing 
13    costs, and related costs resulting from requirements 
14    imposed through other provisions of State law. As used in 
15    this paragraph (5), "cost-effective" means a bidder's bid 
16    price that does not exceed confidential price benchmarks.
17        (6) All procurements under this subsection (d-20) 
18    shall comply with the geographic requirements in 
19    subparagraph (I) of paragraph (1) of subsection (c) of 
20    Section 1-75 and shall follow the procurement processes 
21    and procedures described in this Section and Section 
22    16-111.5 of the Public Utilities Act, to the extent 
23    practicable. The processes and procedures may be expedited 
24    to accommodate the schedule established by this Section. 
25    The Agency shall require all bidders to pay to the Agency a 
26    nonrefundable deposit determined by the Agency and no less 
 
 
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1    than $10,000 per bid as practical. The Agency may also 
2    assess bidder and supplier fees to cover the cost of 
3    procurement events and develop collateral requirements to 
4    maximize the likelihood of successful project development. 
5    Bidders in the initial and additional procurements 
6    described in paragraph (3) of this subsection (d-20) shall 
7    also demonstrate experience in developing to commercial 
8    readiness. As used in this paragraph (6), "developing to 
9    commercial readiness" means having notice to proceed in 
10    owning or operating energy facilities with a combined 
11    nameplate capacity of at least 100 megawatts.
12        (7) In order to advance priority access to the clean 
13    energy economy for businesses and workers from communities 
14    that have been excluded from economic opportunities in the 
15    energy sector, have been subject to disproportionate 
16    levels of pollution, and have disproportionately 
17    experienced negative public health outcomes, the Agency 
18    shall apply its equity accountability system and minimum 
19    equity standards established under subsections (c-10), 
20    (c-15), (c-20), (c-25), and (c-30) of this Section to 
21    energy storage procurement and programs and may include 
22    any proposed modifications to the equity accountability 
23    system and minimum equity standards that may be warranted 
24    with respect to energy storage resources in its plan 
25    submission to the Commission under Section 16-111.5 of the 
26    Public Utilities Act.
 
 
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1        (8) Projects shall be developed in compliance with the 
2    prevailing wage and project labor agreement requirements 
3    for renewable energy projects in subparagraph (Q) of 
4    paragraph (1) of subsection (c) of Section 1-75.
5        (9) An entity operating an energy storage facility 
6    shall demonstrate that it has entered into a labor peace 
7    agreement with a bona fide labor organization that is 
8    actively engaged in representing its employees. The labor 
9    peace agreement shall apply to the employees necessary for 
10    the ongoing maintenance and operation of the energy 
11    storage facility. The existence of a labor peace agreement 
12    shall be an ongoing material condition of an entity's 
13    authorization to maintain and operate the energy storage 
14    facility.    
15        (10) In order to promote the competitive development 
16    of energy storage systems in furtherance of the State's 
17    interest in the health, safety, and welfare of its 
18    residents, storage credits shall not be eligible to be 
19    selected under this subsection (d-20) if the energy 
20    storage resources are sourced from an energy storage 
21    system whose costs were being recovered through rates 
22    regulated by the State or any other state or states on or 
23    after January 1, 2017. No entity shall be permitted to bid 
24    unless it certifies to the Agency that it is not an 
25    electric utility, as defined in Section 16-102 of the 
26    Public Utilities Act, serving more than 10,000 customers 
 
 
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1    in the State.
2        (11) The Agency shall require, as a prerequisite to 
3    payment for any storage credits, that the winning bidder 
4    provide the Agency or its designee a copy of the 
5    interconnection agreement under which the applicable 
6    energy storage system is connected to the transmission or 
7    distribution system.
8        (12) Contracts shall provide that, if the cost 
9    recovery mechanism referenced in subsection (k) of Section 
10    16-108 of the Public Utilities Act remains in full force 
11    without amendment or the utility is otherwise authorized 
12    or entitled to full, prompt, and uninterrupted recovery of 
13    its costs through any other mechanism, then such seller 
14    shall be entitled to full, prompt, and uninterrupted 
15    payment under the applicable contract notwithstanding the 
16    application of this paragraph (12).    
17    (e) The draft procurement plans are subject to public 
18comment, as required by Section 16-111.5 of the Public 
19Utilities Act.
20    (f) The Agency shall submit the final procurement plan to 
21the Commission. The Agency shall revise a procurement plan if 
22the Commission determines that it does not meet the standards 
23set forth in Section 16-111.5 of the Public Utilities Act.
24    (g) The Agency shall assess fees to each affected utility 
25to recover the costs incurred in preparation of procurement 
26plans and in the operation of programs the annual procurement 
 
 
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1plan for the utility.
2    (h) The Agency shall assess fees to each bidder to recover 
3the costs incurred in connection with a competitive 
4procurement process.
5    (i) A renewable energy credit, carbon emission credit, 
6zero emission credit, or carbon mitigation credit can only be 
7used once to comply with a single portfolio or other standard 
8as set forth in subsection (c), subsection (d), or subsection 
9(d-5) of this Section, respectively. A renewable energy 
10credit, carbon emission credit, zero emission credit, or 
11carbon mitigation credit cannot be used to satisfy the 
12requirements of more than one standard. If more than one type 
13of credit is issued for the same megawatt hour of energy, only 
14one credit can be used to satisfy the requirements of a single 
15standard. After such use, the credit must be retired together 
16with any other credits issued for the same megawatt hour of 
17energy. 
18(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 
19103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)
 
20    (20 ILCS 3855/1-125)
21    Sec. 1-125. Agency annual reports. 
22    (a) By March February 15 of each year, the Agency shall 
23report annually to the Governor and the General Assembly on 
24the operations and transactions of the Agency. The annual 
25report shall include, but not be limited to, each of the 
 
 
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1following:
2        (1) The average quantity, price, and term of all 
3    contracts for electricity procured under the procurement 
4    plans for electric utilities.
5        (2) (Blank).
6        (3) The quantity, price, and rate impact of all energy 
7    efficiency and demand response measures purchased for 
8    electric utilities, and any measures included in the 
9    procurement plan pursuant to Section 16-111.5B of the 
10    Public Utilities Act.
11        (4) The amount of power and energy produced by each 
12    Agency facility.
13        (5) The quantity of electricity supplied by each 
14    Agency facility to municipal electric systems, 
15    governmental aggregators, or rural electric cooperatives 
16    in Illinois.
17        (6) The revenues as allocated by the Agency to each 
18    facility.
19        (7) The costs as allocated by the Agency to each 
20    facility.
21        (8) The accumulated depreciation for each facility.
22        (9) The status of any projects under development.
23        (10) Basic financial and operating information 
24    specifically detailed for the reporting year and 
25    including, but not limited to, income and expense 
26    statements, balance sheets, and changes in financial 
 
 
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1    position, all in accordance with generally accepted 
2    accounting principles, debt structure, and a summary of 
3    funds on a cash basis.
4        (11) The average quantity, price, contract type and 
5    term, and rate impact of all renewable resources procured 
6    under the long-term renewable resources procurement plans 
7    for electric utilities. 
8        (12) A comparison of the costs associated with the 
9    Agency's procurement of renewable energy resources to (A) 
10    the Agency's costs associated with electricity generated 
11    by other types of generation facilities and (B) the 
12    benefits associated with the Agency's procurement of 
13    renewable energy resources.
14        (13) An analysis of the rate impacts associated with 
15    the Illinois Power Agency's procurement of renewable 
16    resources, including, but not limited to, any long-term 
17    contracts, on the eligible retail customers of electric 
18    utilities. The analysis shall include the Agency's 
19    estimate of the total dollar impact that the Agency's 
20    procurement of renewable resources has had on the annual 
21    electricity bills of the customer classes that comprise 
22    each eligible retail customer class taking service from an 
23    electric utility.
24        (14) (Blank).
25    (b) In addition to reporting on the transactions and 
26operations of the Agency, the Agency shall also endeavor to 
 
 
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1report on the following items through its annual report, 
2recognizing that full and accurate information may not be 
3available for certain items:
4        (1) The overall nameplate capacity amount of installed 
5    and scheduled renewable energy generation capacity 
6    physically located in Illinois.
7        (2) The percentage of installed and scheduled 
8    renewable energy generation capacity as a share of overall 
9    electricity generation capacity physically located in 
10    Illinois.
11        (3) The amount of megawatt hours produced by renewable 
12    energy generation capacity physically located in Illinois 
13    for the preceding delivery year.
14        (4) The percentage of megawatt hours produced by 
15    renewable energy generation capacity physically located in 
16    Illinois as a share of overall electricity generation from 
17    facilities physically located in Illinois for the 
18    preceding delivery year and as a share of retail 
19    electricity sales in Illinois.
20        (5) The renewable portfolio standard expenditures made 
21    pursuant to paragraph (1) of subsection (c) of Section 
22    1-75 and the total scheduled and installed renewable 
23    generation capacity expected to result from these 
24    investments. This information shall include the total cost 
25    of REC delivery contracts of the renewable portfolio 
26    standard by project category, including, but not limited 
 
 
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1    to, renewable energy credits delivery contracts entered 
2    into pursuant to subparagraphs (C), (G), (K), and (R) of 
3    paragraph (1) of subsection (c) Section 1-75. The Agency 
4    shall also report on the total amount of customer load 
5    featuring renewable portfolio standard compliance 
6    obligations scheduled to be met by self-direct customers 
7    pursuant to subparagraph (R) of paragraph (1) of 
8    subsection (c) of Section 1-75, as well as the minimum 
9    annual quantities of renewable energy credits scheduled to 
10    be retired by those customers and amount of installed 
11    renewable energy generating capacity used to meet the 
12    requirements of subparagraph (R) of paragraph (1) of 
13    subsection (c) of Section 1-75.
14    The Agency may seek assistance from the Illinois Commerce 
15Commission in developing its annual report and may also retain 
16the services of its expert consulting firm used to develop its 
17procurement plans as outlined in paragraph (1) of subsection 
18(a) of Section 1-75. Confidential or commercially sensitive 
19business information provided by retail customers, alternative 
20retail electric suppliers, or other parties shall be kept 
21confidential by the Agency consistent with Section 1-120, but 
22may be publicly reported in aggregate form. 
23(Source: P.A. 102-662, eff. 9-15-21.)
 
24    Section 90-15. The Illinois Procurement Code is amended by 
25changing Sections 1-10 and 30-20 as follows:
 
 
 
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1    (30 ILCS 500/1-10)
2    Sec. 1-10. Application. 
3    (a) This Code applies only to procurements for which 
4bidders, offerors, potential contractors, or contractors were 
5first solicited on or after July 1, 1998. This Code shall not 
6be construed to affect or impair any contract, or any 
7provision of a contract, entered into based on a solicitation 
8prior to the implementation date of this Code as described in 
9Article 99, including, but not limited to, any covenant 
10entered into with respect to any revenue bonds or similar 
11instruments. All procurements for which contracts are 
12solicited between the effective date of Articles 50 and 99 and 
13July 1, 1998 shall be substantially in accordance with this 
14Code and its intent.
15    (b) This Code shall apply regardless of the source of the 
16funds with which the contracts are paid, including federal 
17assistance moneys. This Code shall not apply to:
18        (1) Contracts between the State and its political 
19    subdivisions or other governments, or between State 
20    governmental bodies, except as specifically provided in 
21    this Code.
22        (2) Grants, except for the filing requirements of 
23    Section 20-80.
24        (3) Purchase of care, except as provided in Section 
25    5-30.6 of the Illinois Public Aid Code and this Section.
 
 
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1        (4) Hiring of an individual as an employee and not as 
2    an independent contractor, whether pursuant to an 
3    employment code or policy or by contract directly with 
4    that individual.
5        (5) Collective bargaining contracts.
6        (6) Purchase of real estate, except that notice of 
7    this type of contract with a value of more than $25,000 
8    must be published in the Procurement Bulletin within 10 
9    calendar days after the deed is recorded in the county of 
10    jurisdiction. The notice shall identify the real estate 
11    purchased, the names of all parties to the contract, the 
12    value of the contract, and the effective date of the 
13    contract.
14        (7) Contracts necessary to prepare for anticipated 
15    litigation, enforcement actions, or investigations, 
16    provided that the chief legal counsel to the Governor 
17    shall give his or her prior approval when the procuring 
18    agency is one subject to the jurisdiction of the Governor, 
19    and provided that the chief legal counsel of any other 
20    procuring entity subject to this Code shall give his or 
21    her prior approval when the procuring entity is not one 
22    subject to the jurisdiction of the Governor.
23        (8) (Blank).
24        (9) Procurement expenditures by the Illinois 
25    Conservation Foundation when only private funds are used.
26        (10) (Blank). 
 
 
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1        (11) Public-private agreements entered into according 
2    to the procurement requirements of Section 20 of the 
3    Public-Private Partnerships for Transportation Act and 
4    design-build agreements entered into according to the 
5    procurement requirements of Section 25 of the 
6    Public-Private Partnerships for Transportation Act.
7        (12) (A) Contracts for legal, financial, and other 
8    professional and artistic services entered into by the 
9    Illinois Finance Authority in which the State of Illinois 
10    is not obligated. Such contracts shall be awarded through 
11    a competitive process authorized by the members of the 
12    Illinois Finance Authority and are subject to Sections 
13    5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, 
14    as well as the final approval by the members of the 
15    Illinois Finance Authority of the terms of the contract.
16        (B) Contracts for legal and financial services entered 
17    into by the Illinois Housing Development Authority in 
18    connection with the issuance of bonds in which the State 
19    of Illinois is not obligated. Such contracts shall be 
20    awarded through a competitive process authorized by the 
21    members of the Illinois Housing Development Authority and 
22    are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, 
23    and 50-37 of this Code, as well as the final approval by 
24    the members of the Illinois Housing Development Authority 
25    of the terms of the contract. 
26        (13) Contracts for services, commodities, and 
 
 
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1    equipment to support the delivery of timely forensic 
2    science services in consultation with and subject to the 
3    approval of the Chief Procurement Officer as provided in 
4    subsection (d) of Section 5-4-3a of the Unified Code of 
5    Corrections, except for the requirements of Sections 
6    20-60, 20-65, 20-70, and 20-160 and Article 50 of this 
7    Code; however, the Chief Procurement Officer may, in 
8    writing with justification, waive any certification 
9    required under Article 50 of this Code. For any contracts 
10    for services which are currently provided by members of a 
11    collective bargaining agreement, the applicable terms of 
12    the collective bargaining agreement concerning 
13    subcontracting shall be followed.
14        On and after January 1, 2019, this paragraph (13), 
15    except for this sentence, is inoperative. 
16        (14) Contracts for participation expenditures required 
17    by a domestic or international trade show or exhibition of 
18    an exhibitor, member, or sponsor.
19        (15) Contracts with a railroad or utility that 
20    requires the State to reimburse the railroad or utilities 
21    for the relocation of utilities for construction or other 
22    public purpose. Contracts included within this paragraph 
23    (15) shall include, but not be limited to, those 
24    associated with: relocations, crossings, installations, 
25    and maintenance. For the purposes of this paragraph (15), 
26    "railroad" means any form of non-highway ground 
 
 
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1    transportation that runs on rails or electromagnetic 
2    guideways and "utility" means: (1) public utilities as 
3    defined in Section 3-105 of the Public Utilities Act, (2) 
4    telecommunications carriers as defined in Section 13-202 
5    of the Public Utilities Act, (3) electric cooperatives as 
6    defined in Section 3.4 of the Electric Supplier Act, (4) 
7    telephone or telecommunications cooperatives as defined in 
8    Section 13-212 of the Public Utilities Act, (5) rural 
9    water or waste water systems with 10,000 connections or 
10    less, (6) a holder as defined in Section 21-201 of the 
11    Public Utilities Act, and (7) municipalities owning or 
12    operating utility systems consisting of public utilities 
13    as that term is defined in Section 11-117-2 of the 
14    Illinois Municipal Code. 
15        (16) Procurement expenditures necessary for the 
16    Department of Public Health to provide the delivery of 
17    timely newborn screening services in accordance with the 
18    Newborn Metabolic Screening Act. 
19        (17) Procurement expenditures necessary for the 
20    Department of Agriculture, the Department of Financial and 
21    Professional Regulation, the Department of Human Services, 
22    and the Department of Public Health to implement the 
23    Compassionate Use of Medical Cannabis Program and Opioid 
24    Alternative Pilot Program requirements and ensure access 
25    to medical cannabis for patients with debilitating medical 
26    conditions in accordance with the Compassionate Use of 
 
 
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1    Medical Cannabis Program Act.
2        (18) This Code does not apply to any procurements 
3    necessary for the Department of Agriculture, the 
4    Department of Financial and Professional Regulation, the 
5    Department of Human Services, the Department of Commerce 
6    and Economic Opportunity, and the Department of Public 
7    Health to implement the Cannabis Regulation and Tax Act if 
8    the applicable agency has made a good faith determination 
9    that it is necessary and appropriate for the expenditure 
10    to fall within this exemption and if the process is 
11    conducted in a manner substantially in accordance with the 
12    requirements of Sections 20-160, 25-60, 30-22, 50-5, 
13    50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35, 
14    50-36, 50-37, 50-38, and 50-50 of this Code; however, for 
15    Section 50-35, compliance applies only to contracts or 
16    subcontracts over $100,000. Notice of each contract 
17    entered into under this paragraph (18) that is related to 
18    the procurement of goods and services identified in 
19    paragraph (1) through (9) of this subsection shall be 
20    published in the Procurement Bulletin within 14 calendar 
21    days after contract execution. The Chief Procurement 
22    Officer shall prescribe the form and content of the 
23    notice. Each agency shall provide the Chief Procurement 
24    Officer, on a monthly basis, in the form and content 
25    prescribed by the Chief Procurement Officer, a report of 
26    contracts that are related to the procurement of goods and 
 
 
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1    services identified in this subsection. At a minimum, this 
2    report shall include the name of the contractor, a 
3    description of the supply or service provided, the total 
4    amount of the contract, the term of the contract, and the 
5    exception to this Code utilized. A copy of any or all of 
6    these contracts shall be made available to the Chief 
7    Procurement Officer immediately upon request. The Chief 
8    Procurement Officer shall submit a report to the Governor 
9    and General Assembly no later than November 1 of each year 
10    that includes, at a minimum, an annual summary of the 
11    monthly information reported to the Chief Procurement 
12    Officer. This exemption becomes inoperative 5 years after 
13    June 25, 2019 (the effective date of Public Act 101-27).
14        (19) Acquisition of modifications or adjustments, 
15    limited to assistive technology devices and assistive 
16    technology services, adaptive equipment, repairs, and 
17    replacement parts to provide reasonable accommodations (i) 
18    that enable a qualified applicant with a disability to 
19    complete the job application process and be considered for 
20    the position such qualified applicant desires, (ii) that 
21    modify or adjust the work environment to enable a 
22    qualified current employee with a disability to perform 
23    the essential functions of the position held by that 
24    employee, (iii) to enable a qualified current employee 
25    with a disability to enjoy equal benefits and privileges 
26    of employment as are enjoyed by other similarly situated 
 
 
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1    employees without disabilities, and (iv) that allow a 
2    customer, client, claimant, or member of the public 
3    seeking State services full use and enjoyment of and 
4    access to its programs, services, or benefits. 
5        For purposes of this paragraph (19):
6        "Assistive technology devices" means any item, piece 
7    of equipment, or product system, whether acquired 
8    commercially off the shelf, modified, or customized, that 
9    is used to increase, maintain, or improve functional 
10    capabilities of individuals with disabilities.
11        "Assistive technology services" means any service that 
12    directly assists an individual with a disability in 
13    selection, acquisition, or use of an assistive technology 
14    device.
15        "Qualified" has the same meaning and use as provided 
16    under the federal Americans with Disabilities Act when 
17    describing an individual with a disability. 
18        (20) Procurement expenditures necessary for the 
19    Illinois Commerce Commission to hire third-party 
20    facilitators pursuant to Sections 16-105.17 and 16-108.18 
21    of the Public Utilities Act or an ombudsman pursuant to 
22    Section 16-107.5 of the Public Utilities Act, a 
23    facilitator pursuant to Section 16-105.17 of the Public 
24    Utilities Act, or a grid auditor pursuant to Section 
25    16-105.10 of the Public Utilities Act, a facilitator, 
26    expert, or consultant pursuant to Sections 8-104A, 
 
 
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1    16-126.2, and 16-202 of the Public Utilities Act, a 
2    procurement monitor pursuant to Section 16-111.5 of the 
3    Public Utilities Act, an ombudsperson pursuant to Section 
4    20-145 of the Public Utilities Act, or consultants and 
5    experts pursuant to Section 15 of the Utility Data Access 
6    Act. 
7        (21) Procurement expenditures for the purchase, 
8    renewal, and expansion of software, software licenses, or 
9    software maintenance agreements that support the efforts 
10    of the Illinois State Police to enforce, regulate, and 
11    administer the Firearm Owners Identification Card Act, the 
12    Firearm Concealed Carry Act, the Firearms Restraining 
13    Order Act, the Firearm Dealer License Certification Act, 
14    the Law Enforcement Agencies Data System (LEADS), the 
15    Uniform Crime Reporting Act, the Criminal Identification 
16    Act, the Illinois Uniform Conviction Information Act, and 
17    the Gun Trafficking Information Act, or establish or 
18    maintain record management systems necessary to conduct 
19    human trafficking investigations or gun trafficking or 
20    other stolen firearm investigations. This paragraph (21) 
21    applies to contracts entered into on or after January 10, 
22    2023 (the effective date of Public Act 102-1116) and the 
23    renewal of contracts that are in effect on January 10, 
24    2023 (the effective date of Public Act 102-1116). 
25        (22) Contracts for project management services and 
26    system integration services required for the completion of 
 
 
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1    the State's enterprise resource planning project. This 
2    exemption becomes inoperative 5 years after June 7, 2023 
3    (the effective date of the changes made to this Section by 
4    Public Act 103-8). This paragraph (22) applies to 
5    contracts entered into on or after June 7, 2023 (the 
6    effective date of the changes made to this Section by 
7    Public Act 103-8) and the renewal of contracts that are in 
8    effect on June 7, 2023 (the effective date of the changes 
9    made to this Section by Public Act 103-8). 
10        (23) Procurements necessary for the Department of 
11    Insurance to implement the Illinois Health Benefits 
12    Exchange Law if the Department of Insurance has made a 
13    good faith determination that it is necessary and 
14    appropriate for the expenditure to fall within this 
15    exemption. The procurement process shall be conducted in a 
16    manner substantially in accordance with the requirements 
17    of Sections 20-160 and 25-60 and Article 50 of this Code. A 
18    copy of these contracts shall be made available to the 
19    Chief Procurement Officer immediately upon request. This 
20    paragraph is inoperative 5 years after June 27, 2023 (the 
21    effective date of Public Act 103-103). 
22        (24) Contracts for public education programming, 
23    noncommercial sustaining announcements, public service 
24    announcements, and public awareness and education 
25    messaging with the nonprofit trade associations of the 
26    providers of those services that inform the public on 
 
 
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1    immediate and ongoing health and safety risks and hazards. 
2        (25) Procurements necessary for the Department of 
3    Early Childhood to implement the Department of Early 
4    Childhood Act if the Department has made a good faith 
5    determination that it is necessary and appropriate for the 
6    expenditure to fall within this exemption. This exemption 
7    shall only be used for products and services procured 
8    solely for use by the Department of Early Childhood. The 
9    procurements may include those necessary to design and 
10    build integrated, operational systems of programs and 
11    services. The procurements may include, but are not 
12    limited to, those necessary to align and update program 
13    standards, integrate funding systems, design and establish 
14    data and reporting systems, align and update models for 
15    technical assistance and professional development, design 
16    systems to manage grants and ensure compliance, design and 
17    implement management and operational structures, and 
18    establish new means of engaging with families, educators, 
19    providers, and stakeholders. The procurement processes 
20    shall be conducted in a manner substantially in accordance 
21    with the requirements of Article 50 (ethics) and Sections 
22    5-5 (Procurement Policy Board), 5-7 (Commission on Equity 
23    and Inclusion), 20-80 (contract files), 20-120 
24    (subcontractors), 20-155 (paperwork), 20-160 
25    (ethics/campaign contribution prohibitions), 25-60 
26    (prevailing wage), and 25-90 (prohibited and authorized 
 
 
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1    cybersecurity) of this Code. Beginning January 1, 2025, 
2    the Department of Early Childhood shall provide a 
3    quarterly report to the General Assembly detailing a list 
4    of expenditures and contracts for which the Department 
5    uses this exemption. This paragraph is inoperative on and 
6    after July 1, 2027. 
7        (26) (25) Procurements that are necessary for 
8    increasing the recruitment and retention of State 
9    employees, particularly minority candidates for 
10    employment, including: 
11            (A) procurements related to registration fees for 
12        job fairs and other outreach and recruitment events;
13            (B) production of recruitment materials; and
14            (C) other services related to recruitment and 
15        retention of State employees.
16        The exemption under this paragraph (26) (25) applies 
17    only if the State agency has made a good faith 
18    determination that it is necessary and appropriate for the 
19    expenditure to fall within this paragraph (26) (25). The 
20    procurement process under this paragraph (26) (25) shall 
21    be conducted in a manner substantially in accordance with 
22    the requirements of Sections 20-160 and 25-60 and Article 
23    50 of this Code. A copy of these contracts shall be made 
24    available to the Chief Procurement Officer immediately 
25    upon request. Nothing in this paragraph (26) (25)    
26    authorizes the replacement or diminishment of State 
 
 
10400SB0025ham002- 378 -LRB104 07069 AAS 28576 a

1    responsibilities in hiring or the positions that 
2    effectuate that hiring. This paragraph (26) (25) is 
3    inoperative on and after June 30, 2029. 
4    Notwithstanding any other provision of law, for contracts 
5with an annual value of more than $100,000 entered into on or 
6after October 1, 2017 under an exemption provided in any 
7paragraph of this subsection (b), except paragraph (1), (2), 
8or (5), each State agency shall post to the appropriate 
9procurement bulletin the name of the contractor, a description 
10of the supply or service provided, the total amount of the 
11contract, the term of the contract, and the exception to the 
12Code utilized. The chief procurement officer shall submit a 
13report to the Governor and General Assembly no later than 
14November 1 of each year that shall include, at a minimum, an 
15annual summary of the monthly information reported to the 
16chief procurement officer. 
17    (c) This Code does not apply to the electric power 
18procurement process provided for under Section 1-75 of the 
19Illinois Power Agency Act and Section 16-111.5 of the Public 
20Utilities Act. This Code does not apply to the procurement of 
21technical and policy experts pursuant to Section 1-129 of the 
22Illinois Power Agency Act. 
23    (d) Except for Section 20-160 and Article 50 of this Code, 
24and as expressly required by Section 9.1 of the Illinois 
25Lottery Law, the provisions of this Code do not apply to the 
26procurement process provided for under Section 9.1 of the 
 
 
10400SB0025ham002- 379 -LRB104 07069 AAS 28576 a

1Illinois Lottery Law. 
2    (e) This Code does not apply to the process used by the 
3Capital Development Board to retain a person or entity to 
4assist the Capital Development Board with its duties related 
5to the determination of costs of a clean coal SNG brownfield 
6facility, as defined by Section 1-10 of the Illinois Power 
7Agency Act, as required in subsection (h-3) of Section 9-220 
8of the Public Utilities Act, including calculating the range 
9of capital costs, the range of operating and maintenance 
10costs, or the sequestration costs or monitoring the 
11construction of clean coal SNG brownfield facility for the 
12full duration of construction.
13    (f) (Blank). 
14    (g) (Blank).
15    (h) This Code does not apply to the process to procure or 
16contracts entered into in accordance with Sections 11-5.2 and 
1711-5.3 of the Illinois Public Aid Code. 
18    (i) Each chief procurement officer may access records 
19necessary to review whether a contract, purchase, or other 
20expenditure is or is not subject to the provisions of this 
21Code, unless such records would be subject to attorney-client 
22privilege. 
23    (j) This Code does not apply to the process used by the 
24Capital Development Board to retain an artist or work or works 
25of art as required in Section 14 of the Capital Development 
26Board Act. 
 
 
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1    (k) This Code does not apply to the process to procure 
2contracts, or contracts entered into, by the State Board of 
3Elections or the State Electoral Board for hearing officers 
4appointed pursuant to the Election Code. 
5    (l) This Code does not apply to the processes used by the 
6Illinois Student Assistance Commission to procure supplies and 
7services paid for from the private funds of the Illinois 
8Prepaid Tuition Fund. As used in this subsection (l), "private 
9funds" means funds derived from deposits paid into the 
10Illinois Prepaid Tuition Trust Fund and the earnings thereon. 
11    (m) This Code shall apply regardless of the source of 
12funds with which contracts are paid, including federal 
13assistance moneys. Except as specifically provided in this 
14Code, this Code shall not apply to procurement expenditures 
15necessary for the Department of Public Health to conduct the 
16Healthy Illinois Survey in accordance with Section 2310-431 of 
17the Department of Public Health Powers and Duties Law of the 
18Civil Administrative Code of Illinois. 
19(Source: P.A. 102-175, eff. 7-29-21; 102-483, eff 1-1-22; 
20102-558, eff. 8-20-21; 102-600, eff. 8-27-21; 102-662, eff. 
219-15-21; 102-721, eff. 1-1-23; 102-813, eff. 5-13-22; 
22102-1116, eff. 1-10-23; 103-8, eff. 6-7-23; 103-103, eff. 
236-27-23; 103-570, eff. 1-1-24; 103-580, eff. 12-8-23; 103-594, 
24eff. 6-25-24; 103-605, eff. 7-1-24; 103-865, eff. 1-1-25; 
25revised 11-26-24.)
 
 
 
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1    (30 ILCS 500/30-20)
2    Sec. 30-20. Prequalification. 
3    (a) The Capital Development Board shall promulgate rules 
4for the development of prequalified supplier lists for 
5construction and construction-related professional services 
6and the periodic updating of those lists. Construction and 
7construction-related professional services contracts over 
8$25,000 may be awarded to any qualified suppliers.
9    (b) If deemed necessary by the Agency, the The Illinois 
10Power Agency shall promulgate rules for the development of 
11prequalified supplier lists for construction and 
12construction-related professional services and the periodic 
13updating of those lists. Construction and construction-related    
14construction related professional services contracts over 
15$25,000 may be awarded to any qualified suppliers, pursuant to 
16a competitive bidding process. 
17(Source: P.A. 95-481, eff. 8-28-07.)
 
18    Section 90-17. The Illinois Works Jobs Program Act is 
19amended by changing Section 20-15 as follows:
 
20    (30 ILCS 559/20-15)
21    Sec. 20-15. Illinois Works Preapprenticeship Program; 
22Illinois Works Bid Credit Program. 
23    (a) The Illinois Works Preapprenticeship Program is 
24established and shall be administered by the Department. The 
 
 
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1goal of the Illinois Works Preapprenticeship Program is to 
2create a network of community-based organizations throughout 
3the State that will recruit, prescreen, and provide 
4preapprenticeship skills training, for which participants may 
5attend free of charge and receive a stipend, to create a 
6qualified, diverse pipeline of workers who are prepared for 
7careers in the construction and building trades. Upon 
8completion of the Illinois Works Preapprenticeship Program, 
9the candidates will be skilled and work-ready. 
10    (b) There is created the Illinois Works Fund, a special 
11fund in the State treasury. The Illinois Works Fund shall be 
12administered by the Department. The Illinois Works Fund shall 
13be used to provide funding for community-based organizations 
14throughout the State. In addition to any other transfers that 
15may be provided for by law, on and after July 1, 2019 at the 
16direction of the Director of the Governor's Office of 
17Management and Budget, the State Comptroller shall direct and 
18the State Treasurer shall transfer amounts not exceeding a 
19total of $50,000,000 from the Rebuild Illinois Projects Fund 
20to the Illinois Works Fund.
21    (b-5) In addition to any other transfers that may be 
22provided for by law, beginning July 1, 2024 and each July 1 
23thereafter, or as soon thereafter as practical, the State 
24Comptroller shall direct and the State Treasurer shall 
25transfer $27,500,000 from the Capital Projects Fund to the 
26Illinois Works Fund. 
 
 
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1    (c) Each community-based organization that receives 
2funding from the Illinois Works 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 community-based 
7    organization's recruitment, screening, and training 
8    efforts; 
9        (2) the number of individuals who apply to, 
10    participate in, and complete the community-based 
11    organization's program, broken down by race, gender, age, 
12    and veteran status; and
13    (3) the number of the individuals referenced in item (2) 
14    of this subsection who are initially accepted and placed 
15    into apprenticeship programs in the construction and 
16    building trades. 
17    (d) The Department shall create and administer the 
18Illinois Works Bid Credit Program that shall provide economic 
19incentives, through bid credits, to encourage contractors and 
20subcontractors to provide contracting and employment 
21opportunities to historically underrepresented populations in 
22the construction industry. 
23    The Illinois Works Bid Credit Program shall allow 
24contractors and subcontractors to earn bid credits for use 
25toward future bids for public works projects contracted by the 
26State or an agency of the State in order to increase the 
 
 
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1chances that the contractor and the subcontractors will be 
2selected.
3    Contractors or subcontractors may be eligible to earn bid 
4credits for employing apprentices who have been verified by 
5the Department to have completed the Illinois Works 
6Preapprenticeship Program, the Climate Works Preapprenticeship 
7Program, or the Highway Construction Careers Training Program. 
8Contractors or subcontractors shall earn bid credits at a rate 
9established by the Department and based on labor hours worked 
10by apprentices who have been verified by the Department to 
11have completed the Illinois Works Preapprenticeship Program, 
12the Climate Works Preapprenticeship Program, or the Highway 
13Construction Careers Training Program. In order to earn bid 
14credits, contractors and subcontractors shall provide the 
15Department with certified payroll documenting the hours 
16performed by apprentices who have been verified by the 
17Department to have completed the Illinois Works 
18Preapprenticeship Program, the Climate Works Preapprenticeship 
19Program, or the Highway Construction Careers Training Program. 
20Contractors and subcontractors can use bid credits toward 
21future bids for public works projects contracted or funded by 
22the State or an agency of the State in order to increase the 
23likelihood of being selected as the contractor for the public 
24works project toward which they have applied the bid credit. 
25The Department shall establish the rate by rule and shall 
26publish it on the Department's website. The rule may include 
 
 
10400SB0025ham002- 385 -LRB104 07069 AAS 28576 a

1maximum bid credits allowed per contractor, per subcontractor, 
2per apprentice, per bid, or per year. 
3    The Illinois Works Credit Bank is hereby created and shall 
4be administered by the Department. The Illinois Works Credit 
5Bank shall track the bid credits. 
6    A contractor or subcontractor who has been awarded bid 
7credits under any other State program for employing 
8apprentices who have completed the Illinois Works 
9Preapprenticeship Program is not eligible to receive bid 
10credits under the Illinois Works Bid Credit Program relating 
11to the same contract.
12    The Department shall report to the Illinois Works Review 
13Panel the following: (i) the number of bid credits awarded by 
14the Department; (ii) the number of bid credits submitted by 
15the contractor or subcontractor to the agency administering 
16the public works contract; and (iii) the number of bid credits 
17accepted by the agency for such contract. Any agency that 
18awards bid credits pursuant to the Illinois Works Credit Bank 
19Program shall report to the Department the number of bid 
20credits it accepted for the public works contract.
21    Upon a finding that a contractor or subcontractor has 
22reported falsified records to the Department in order to 
23fraudulently obtain bid credits, the Department may bar the 
24contractor or subcontractor from participating in the Illinois 
25Works Bid Credit Program and may suspend the contractor or 
26subcontractor from bidding on or participating in any public 
 
 
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1works project. False or fraudulent claims for payment relating 
2to false bid credits may be subject to damages and penalties 
3under applicable law. 
4    (e) The Department shall adopt any rules deemed necessary 
5to implement this Section. In order to provide for the 
6expeditious and timely implementation of this Act, the 
7Department may adopt emergency rules. The adoption of 
8emergency rules authorized by this subsection is deemed to be 
9necessary for the public interest, safety, and welfare.
10(Source: P.A. 103-8, eff. 6-7-23; 103-305, eff. 7-28-23; 
11103-588, eff. 6-5-24; 103-605, eff. 7-1-24; 104-2, eff. 
126-16-25.)
 
13    Section 90-20. The Property Tax Code is amended by adding 
14Division 22 as follows:
 
15    (35 ILCS 200/Art. 10 Div. 22 heading new)
16
Division 22.  Commercial energy storage systems

 
17    (35 ILCS 200/10-920 new)
18    Sec. 10-920. Definitions. As used in this Division:
19    "Allowance for physical depreciation" means the product of 
20the quotient that is generated by dividing the actual age in 
21years of the commercial energy storage system on the 
22assessment date by 25 years multiplied by the commercial 
23energy storage system's trended real property cost basis. 
 
 
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1"Allowance for physical depreciation" may not exceed an amount 
2that reduces the value of the commercial energy storage system 
3to 30% of its trended real property cost basis or less.
4    "Commercial energy storage system" means any device or 
5assembly of devices that is (i) either installed as a 
6stand-alone system or tied to a power generation system, (ii) 
7used for the primary purpose of storing of energy for 
8wholesale or retail sale and not primarily for storage to 
9later consume on the property on which the device resides, and 
10(iii) an energy storage system, as defined in Section 16-135 
11of the Public Utilities Act.
12    "Commercial energy storage system real property cost 
13basis" means the owner of the commercial energy storage 
14system's interest in the land within the project boundaries 
15and real property improvements and shall be calculated at $65 
16per kilowatt-hour of rated kilowatt-hour energy capacity.
17    "Consumer Price Index" means the index published by the 
18Bureau of Labor Statistics of the United States Department of 
19Labor that measures the average change in prices of goods and 
20services purchased by all urban consumers, United States city 
21average, all items, 1982-84 = 100.
22    "Rated kWh energy capacity" means the maximum amount of 
23stored energy in kilowatt hours. "Trended real property cost 
24basis" means the commercial energy storage system real 
25property cost basis multiplied by the trending factor.
26    "Trending factor" means the following:
 
 
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1        (1) for stand-alone commercial energy storage systems, 
2    the lesser of 2% or the number generated by dividing the 
3    Consumer Price Index published by the Bureau of Labor 
4    Statistics in the December immediately preceding the 
5    assessment date by the Consumer Price Index published by 
6    the Bureau of Labor Statistics in December of 2024; or
7        (2) for commercial energy storage systems tied to a 
8    power generation system, a trending factor of 1.00.
 
9    (35 ILCS 200/10-925 new)
10    Sec. 10-925. Improvement valuation of commercial energy 
11systems. Beginning in assessment year 2026, the fair cash 
12value of commercial energy storage system improvements shall 
13be determined by subtracting the allowance for physical 
14depreciation from the commercial energy storage system trended 
15real property cost basis. Functional obsolescence and external 
16obsolescence of the commercial energy storage system 
17improvements may further reduce the fair cash value of the 
18improvements to the extent the obsolescence is proven by the 
19taxpayer by clear and convincing evidence, except that the 
20combined depreciation from all functional and economic 
21obsolescence shall not exceed 70% of the trended real property 
22cost basis. The chief county assessment officer may make 
23reasonable adjustments to the actual age of the commercial 
24energy storage system to account for the routine replacement 
25or upgrade of system components.
 
 
 
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1    (35 ILCS 200/10-930 new)
2    Sec. 10-930. Commercial energy storage systems; 
3equalization. Commercial energy storage systems that are 
4subject to assessment under this Division are not subject to 
5equalization factors applied by the Department, any board of 
6review, an assessor, or a chief county assessment officer.
 
7    (35 ILCS 200/10-935 new)
8    Sec. 10-935. Survey for commercial energy storage systems; 
9parcel identification numbers. Notwithstanding any other 
10provision of law, the owner of the commercial energy storage 
11system shall commission a metes and bounds survey description 
12of the land upon which the commercial energy storage system is 
13located, including access routes, over which the owner of the 
14commercial energy storage system has exclusive control. Land 
15held for future development shall not be included in the 
16project area for real property assessment purposes. The owner 
17of the commercial energy storage system shall, at the owner's 
18own expense, use a State-registered land surveyor to prepare 
19the survey. The owner of the commercial energy storage system 
20shall deliver a copy of the survey to the chief county 
21assessment officer and to the owner of the land upon which the 
22commercial energy storage system is located. Upon receiving a 
23copy of the survey and an agreed acknowledgment to the 
24separate parcel identification number by the owner of the land 
 
 
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1upon which the commercial energy storage system is 
2constructed, the chief county assessment officer shall issue a 
3separate parcel identification number for the real property 
4improvements, including the land containing the commercial 
5energy storage system, to be used only for the purposes of 
6property assessment for taxation. If no survey is provided, 
7the chief county assessment officer shall determine the area 
8of the site that is occupied by the commercial energy storage 
9system. The chief county assessment officer's determination 
10shall be final and may not be challenged on review by the owner 
11of the commercial energy storage system. The property records 
12shall contain the legal description of the commercial energy 
13storage system parcel and describe any leasehold interest or 
14other interest of the owner of the commercial energy storage 
15system in the property. A plat prepared under this Section 
16shall not be construed as a violation of the Plat Act.
17    Surveys that are prepared in accordance with either 
18Section 10-740 or Section 10-620 and that also include the 
19location of a commercial energy storage system in the survey's 
20metes and bounds description shall satisfy the requirements of 
21this Section.
 
22    (35 ILCS 200/10-940 new)
23    Sec. 10-940. Real estate taxes. Notwithstanding the 
24provisions of Section 9-175 of this Code, the owner of the 
25commercial energy storage system shall be liable for the real 
 
 
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1estate taxes for the land and real property improvements of 
2the commercial energy storage system. Notwithstanding the 
3foregoing, the owner of the land upon which a commercial 
4energy storage system is located may pay any unpaid tax of the 
5commercial energy storage system parcel prior to the 
6initiation of any tax sale proceedings.
 
7    (35 ILCS 200/10-945 new)
8    Sec. 10-945. Property assessed as farmland. 
9Notwithstanding any other provision of law, real property 
10assessed as farmland in accordance with Section 10-110 in the 
11assessment year prior to valuation under this Division shall 
12return to being assessed as farmland in accordance with 
13Section 10-110 in the year following completion of the removal 
14of the commercial energy storage system if the property is 
15returned to a farm use, as defined in Section 1-60, 
16notwithstanding that the land was not used for farming for the 
172 preceding years.
 
18    (35 ILCS 200/10-950 new)
19    Sec. 10-950. Abatements. Any taxing district may, upon a 
20majority vote of its governing authority and after the 
21determination of the assessed valuation as set forth in this 
22Code, order the clerk of the appropriate municipality or 
23county to abate any portion of real property taxes otherwise 
24levied or extended by the taxing district on a commercial 
 
 
10400SB0025ham002- 392 -LRB104 07069 AAS 28576 a

1energy storage system.
 
2    (35 ILCS 200/10-953 new)
3    Sec. 10-953. Cook County exemption. This Division 22 does 
4not apply to any property located within Cook County.
 
5    (35 ILCS 200/10-955 new)
6    Sec. 10-955. Applicability. The provisions of this 
7Division apply for assessment years 2026 through 2040.
 
8    Section 90-26. The Counties Code is amended by adding 
9Division 5-46 and Section 5-12024 and changing Section 5-12020 
10as follows:
 
11    (55 ILCS 5/5-12020)
12    Sec. 5-12020. Commercial wind energy facilities and 
13commercial solar energy facilities. 
14    (a) As used in this Section:
15    "Commercial solar energy facility" means a "commercial 
16solar energy system" as defined in Section 10-720 of the 
17Property Tax Code. "Commercial solar energy facility" does not 
18mean a utility-scale solar energy facility being constructed 
19at a site that was eligible to participate in a procurement 
20event conducted by the Illinois Power Agency pursuant to 
21subsection (c-5) of Section 1-75 of the Illinois Power Agency 
22Act. 
 
 
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1    "Commercial wind energy facility" means a wind energy 
2conversion facility of equal or greater than 500 kilowatts in 
3total nameplate generating capacity. "Commercial wind energy 
4facility" includes a wind energy conversion facility seeking 
5an extension of a permit to construct granted by a county or 
6municipality before January 27, 2023 (the effective date of 
7Public Act 102-1123).
8    "Facility owner" means (i) a person with a direct 
9ownership interest in a commercial wind energy facility or a 
10commercial solar energy facility, or both, regardless of 
11whether the person is involved in acquiring the necessary 
12rights, permits, and approvals or otherwise planning for the 
13construction and operation of the facility, and (ii) at the 
14time the facility is being developed, a person who is acting as 
15a developer of the facility by acquiring the necessary rights, 
16permits, and approvals or by planning for the construction and 
17operation of the facility, regardless of whether the person 
18will own or operate the facility.
19    "Nonparticipating property" means real property that is 
20not a participating property.
21    "Nonparticipating residence" means a residence that is 
22located on nonparticipating property and that is existing and 
23occupied on the date that an application for a permit to 
24develop the commercial wind energy facility or the commercial 
25solar energy facility is filed with the county.
26    "Occupied community building" means any one or more of the 
 
 
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1following buildings that is existing and occupied on the date 
2that the application for a permit to develop the commercial 
3wind energy facility or the commercial solar energy facility 
4is filed with the county: a school, place of worship, day care 
5facility, public library, or community center.
6    "Participating property" means real property that is the 
7subject of a written agreement between a facility owner and 
8the owner of the real property that provides the facility 
9owner an easement, option, lease, or license to use the real 
10property for the purpose of constructing a commercial wind 
11energy facility, a commercial solar energy facility, or 
12supporting facilities. "Participating property" also includes 
13real property that is owned by a facility owner for the purpose 
14of constructing a commercial wind energy facility, a 
15commercial solar energy facility, or supporting facilities.
16    "Participating residence" means a residence that is 
17located on participating property and that is existing and 
18occupied on the date that an application for a permit to 
19develop the commercial wind energy facility or the commercial 
20solar energy facility is filed with the county.
21    "Protected lands" means real property that is: 
22        (1) subject to a permanent conservation right 
23    consistent with the Real Property Conservation Rights Act; 
24    or 
25        (2) registered or designated as a nature preserve, 
26    buffer, or land and water reserve under the Illinois 
 
 
10400SB0025ham002- 395 -LRB104 07069 AAS 28576 a

1    Natural Areas Preservation Act.
2    "Supporting facilities" means the transmission lines, 
3substations, access roads, meteorological towers, storage 
4containers, and equipment associated with the generation and 
5storage of electricity by the commercial wind energy facility 
6or commercial solar energy facility. "Supporting facilities" 
7includes energy storage systems capable of absorbing energy 
8and storing it for use at a later time, including, but not 
9limited to, batteries and other electrochemical and 
10electromechanical technologies or systems.    
11    "Wind tower" includes the wind turbine tower, nacelle, and 
12blades. 
13    (b) Notwithstanding any other provision of law or whether 
14the county has formed a zoning commission and adopted formal 
15zoning under Section 5-12007, a county may establish standards 
16for commercial wind energy facilities, commercial solar energy 
17facilities, or both. The standards may include all of the 
18requirements specified in this Section but may not include 
19requirements for commercial wind energy facilities or 
20commercial solar energy facilities that are more restrictive 
21than specified in this Section. A county may also regulate the 
22siting of commercial wind energy facilities with standards 
23that are not more restrictive than the requirements specified 
24in this Section in unincorporated areas of the county that are 
25outside the zoning jurisdiction of a municipality and that are 
26outside the 1.5-mile radius surrounding the zoning 
 
 
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1jurisdiction of a municipality. A county may also regulate the 
2siting of commercial solar energy facilities with standards 
3that are not more restrictive than the requirements specified 
4in this Section in unincorporated areas of the county that are 
5outside of the zoning jurisdiction of a municipality.    
6    (c) If a county has elected to establish standards under 
7subsection (b), before the county grants siting approval or a 
8special use permit for a commercial wind energy facility or a 
9commercial solar energy facility, or modification of an 
10approved siting or special use permit, the county board of the 
11county in which the facility is to be sited or the zoning board 
12of appeals for the county shall hold at least one public 
13hearing. The public hearing shall be conducted in accordance 
14with the Open Meetings Act and shall conclude be held not more 
15than 60 days after the filing of the application for the 
16facility. The county shall allow interested parties to a 
17special use permit an opportunity to present evidence and to 
18cross-examine witnesses at the hearing, but the county may 
19impose reasonable restrictions on the public hearing, 
20including reasonable time limitations on the presentation of 
21evidence and the cross-examination of witnesses. The county 
22shall also allow public comment at the public hearing in 
23accordance with the Open Meetings Act. The county shall make 
24its siting and permitting decisions not more than 30 days 
25after the conclusion of the public hearing. Notice of the 
26hearing shall be published in a newspaper of general 
 
 
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1circulation in the county. A facility owner must enter into an 
2agricultural impact mitigation agreement with the Department 
3of Agriculture prior to the date of the required public 
4hearing. A commercial wind energy facility owner seeking an 
5extension of a permit granted by a county prior to July 24, 
62015 (the effective date of Public Act 99-132) must enter into 
7an agricultural impact mitigation agreement with the 
8Department of Agriculture prior to a decision by the county to 
9grant the permit extension. Counties may allow test wind 
10towers or test solar energy systems to be sited without formal 
11approval by the county board.
12    (d) A county with an existing zoning ordinance in conflict 
13with this Section shall amend that zoning ordinance to be in 
14compliance with this Section within 120 days after January 27, 
152023 (the effective date of Public Act 102-1123).
16    (e) A county may require: 
17        (1) a wind tower of a commercial wind energy facility 
18    to be sited as follows, with setback distances measured 
19    from the center of the base of the wind tower: 
 
20Setback Description           Setback Distance
 
21Occupied Community            2.1 times the maximum blade tip
22Buildings                     height of the wind tower to the
23                              nearest point on the outside
24                              wall of the structure
 
 
 
10400SB0025ham002- 398 -LRB104 07069 AAS 28576 a

1Participating Residences      1.1 times the maximum blade tip
2                              height of the wind tower to the
3                              nearest point on the outside
4                              wall of the structure
 
5Nonparticipating Residences   2.1 times the maximum blade tip
6                              height of the wind tower to the
7                              nearest point on the outside
8                              wall of the structure
 
9Boundary Lines of             None
10Participating Property 
 
11Boundary Lines of             1.1 times the maximum blade tip
12Nonparticipating Property     height of the wind tower to the
13                              nearest point on the property
14                              line of the nonparticipating
15                              property
 
16Public Road Rights-of-Way     1.1 times the maximum blade tip
17                              height of the wind tower
18                              to the center point of the
19                              public road right-of-way
 
20Overhead Communication and    1.1 times the maximum blade tip
 
 
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1Electric Transmission         height of the wind tower to the
2and Distribution Facilities   nearest edge of the property
3(Not Including Overhead       line, easement, or 
4Utility Service Lines to      right-of-way 
5Individual Houses or          containing the overhead line
6Outbuildings)
 
7Overhead Utility Service      None
8Lines to Individual
9Houses or Outbuildings
 
10Fish and Wildlife Areas       2.1 times the maximum blade
11and Illinois Nature           tip height of the wind tower
12Preserve Commission           to the nearest point on the
13Protected Lands               property line of the fish and
14                              wildlife area or protected
15                              land
16    This Section does not exempt or excuse compliance with 
17    electric facility clearances approved or required by the 
18    National Electrical Code, the The National Electrical 
19    Safety Code, the Illinois Commerce Commission, and the    
20    Federal Energy Regulatory Commission, and their designees 
21    or successors; .    
22        (2) a wind tower of a commercial wind energy facility 
23    to be sited so that industry standard computer modeling 
24    indicates that any occupied community building or 
 
 
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1    nonparticipating residence will not experience more than 
2    30 hours per year of shadow flicker under planned 
3    operating conditions;
4        (3) a commercial solar energy facility to be sited as 
5    follows, with setback distances measured from the nearest 
6    edge of any above-ground component of the facility, 
7    excluding fencing: 
 
8Setback Description           Setback Distance
 
9Occupied Community            150 feet from the nearest
10Buildings and Dwellings on    point on the outside wall 
11Nonparticipating Properties   of the structure
 
12Boundary Lines of             None
13Participating Property    
 
14Public Road Rights-of-Way     50 feet from the nearest
15                              edge of the public 
16                              right-of-way 
 
17Boundary Lines of             50 feet to the nearest
18Nonparticipating Property     point on the property
19                              line of the nonparticipating
20                              property
 
 
 
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1        (4) a commercial solar energy facility to be sited so 
2    that the facility's perimeter is enclosed by fencing 
3    having a height of at least 6 feet and no more than 25 
4    feet; and 
5        (5) a commercial solar energy facility to be sited so 
6    that no component of a solar panel has a height of more 
7    than 20 feet above ground when the solar energy facility's 
8    arrays are at full tilt. 
9    The requirements set forth in this subsection (e) may be 
10waived subject to the written consent of the owner of each 
11affected nonparticipating property.
12    (f) A county may not set a sound limitation for wind towers 
13in commercial wind energy facilities or any components in 
14commercial solar energy facilities that is more restrictive 
15than the sound limitations established by the Illinois 
16Pollution Control Board under 35 Ill. Adm. Code Parts 900, 
17901, and 910.
18    (g) A county may not place any restriction on the 
19installation or use of a commercial wind energy facility or a 
20commercial solar energy facility unless it adopts an ordinance 
21that complies with this Section. A county may not establish 
22siting standards for supporting facilities that preclude 
23development of commercial wind energy facilities or commercial 
24solar energy facilities. 
25    A request for siting approval or a special use permit for a 
26commercial wind energy facility or a commercial solar energy 
 
 
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1facility, or modification of an approved siting or special use 
2permit, shall be approved if the request is in compliance with 
3the standards and conditions imposed in this Act, the zoning 
4ordinance adopted consistent with this Act Code, and the 
5conditions imposed under State and federal statutes and 
6regulations. 
7    (h) A county may not adopt zoning regulations that 
8disallow, permanently or temporarily, commercial wind energy 
9facilities or commercial solar energy facilities from being 
10developed or operated in any district zoned to allow 
11agricultural or industrial uses. 
12    (i) (Blank). A county may not require permit application 
13fees for a commercial wind energy facility or commercial solar 
14energy facility that are unreasonable. All application fees 
15imposed by the county shall be consistent with fees for 
16projects in the county with similar capital value and cost.    
17    (i-5) All siting approval or special use permit 
18application fees for a commercial wind energy facility or 
19commercial solar energy facility shall not exceed $5,000 per 
20each megawatt of nameplate capacity of the energy facility, 
21and the maximum fee is $125,000. A county may also require 
22reimbursement from the applicant for any reasonable expenses 
23incurred by the county in processing the siting approval or 
24special use permit application in excess of the maximum fee. A 
25siting approval or special use permit shall not be subject to 
26any time deadline to start construction or obtain a building 
 
 
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1permit of less than 5 years from the date of siting approval or 
2special use permit approval. A county shall allow an applicant 
3to request an extension of the deadline based upon reasonable 
4cause for the extension request. The exemption shall not be 
5unreasonably withheld, conditioned, or denied.
6    (i-10) A county may require, for a commercial wind energy 
7facility or commercial solar energy facility, a single 
8building permit and permit fee for the facility which includes 
9all supporting facilities. A county building permit fee for a 
10commercial wind energy facility or commercial solar energy 
11facility shall not exceed $5,000 per each megawatt of 
12nameplate capacity of the energy facility, and the maximum fee 
13is $75,000. A county may also require reimbursement from the 
14applicant for any reasonable expenses incurred by the county 
15in processing the building permit in excess of the maximum 
16fee. A county may require an applicant, upon start of 
17construction of the facility, to maintain liability insurance 
18that is commercially reasonable and consistent with prevailing 
19industry standards for similar energy facilities.
20    (j) Except as otherwise provided in this Section, a county 
21shall not require standards for construction, decommissioning, 
22or deconstruction of a commercial wind energy facility or 
23commercial solar energy facility or related financial 
24assurances that are more restrictive than those included in 
25the Department of Agriculture's standard wind farm 
26agricultural impact mitigation agreement, template 81818, or 
 
 
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1standard solar agricultural impact mitigation agreement, 
2version 8.19.19, as applicable and in effect on December 31, 
32022. The amount of any decommissioning payment shall be in 
4accordance with the financial assurance required by those 
5agricultural impact mitigation agreements. 
6    (j-5) A commercial wind energy facility or a commercial 
7solar energy facility shall file a farmland drainage plan with 
8the county and impacted drainage districts outlining how 
9surface and subsurface drainage of farmland will be restored 
10during and following construction or deconstruction of the 
11facility. The plan is to be created independently by the 
12facility developer and shall include the location of any 
13potentially impacted drainage district facilities to the 
14extent this information is publicly available from the county 
15or the drainage district, plans to repair any subsurface 
16drainage affected during construction or deconstruction using 
17procedures outlined in the agricultural impact mitigation 
18agreement entered into by the commercial wind energy facility 
19owner or commercial solar energy facility owner, and 
20procedures for the repair and restoration of surface drainage 
21affected during construction or deconstruction. All surface 
22and subsurface damage shall be repaired as soon as reasonably 
23practicable. 
24    (k) A county may not condition approval of a commercial 
25wind energy facility or commercial solar energy facility on a 
26property value guarantee and may not require a facility owner 
 
 
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1to pay into a neighboring property devaluation escrow account. 
2    (l) A county may require certain vegetative screening 
3between a surrounding a commercial wind energy facility or    
4commercial solar energy facility and nonparticipating 
5residences. A county but may not require earthen berms or 
6similar structures. Vegetative screening requirements shall be 
7commercially reasonable and limited in height at full maturity 
8to avoid reduction of the productive energy output of the 
9commercial solar energy facility. A county may not require 
10vegetative screening to exceed 5 feet in height when first 
11installed or prior to commercial operation date. The screening 
12requirements shall take into account the size and location of 
13the facility, visibility from nonparticipating residences, 
14compatibility of native plant species, cost and feasibility of 
15installation and maintenance, and industry standards and best 
16practices for commercial solar energy facilities.    
17    (m) A county may set blade tip height limitations for wind 
18towers in commercial wind energy facilities but may not set a 
19blade tip height limitation that is more restrictive than the 
20height allowed under a Determination of No Hazard to Air 
21Navigation by the Federal Aviation Administration under 14 CFR 
22Part 77.
23    (n) A county may require that a commercial wind energy 
24facility owner or commercial solar energy facility owner 
25provide:
26        (1) the results and recommendations from consultation 
 
 
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1    with the Illinois Department of Natural Resources that are 
2    obtained through the Ecological Compliance Assessment Tool 
3    (EcoCAT) or a comparable successor tool; and
4        (2) the results of the United States Fish and Wildlife 
5    Service's Information for Planning and Consulting 
6    environmental review or a comparable successor tool that 
7    is consistent with (i) the "U.S. Fish and Wildlife 
8    Service's Land-Based Wind Energy Guidelines" and (ii) any 
9    applicable United States Fish and Wildlife Service solar 
10    wildlife guidelines that have been subject to public 
11    review. 
12    (o) A county may require a commercial wind energy facility 
13or commercial solar energy facility to adhere to the 
14recommendations provided by the Illinois Department of Natural 
15Resources in an EcoCAT natural resource review report under 17 
16Ill. Adm. Code Part 1075. 
17    (p) A county may require a facility owner to:
18        (1) demonstrate avoidance of protected lands as 
19    identified by the Illinois Department of Natural Resources 
20    and the Illinois Nature Preserve Commission; or
21        (2) consider the recommendations of the Illinois 
22    Department of Natural Resources for setbacks from 
23    protected lands, including areas identified by the 
24    Illinois Nature Preserve Commission.
25    (q) A county may require that a facility owner provide 
26evidence of consultation with the Illinois State Historic 
 
 
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1Preservation Office to assess potential impacts on 
2State-registered historic sites under the Illinois State 
3Agency Historic Resources Preservation Act. 
4    (r) To maximize community benefits, including, but not 
5limited to, reduced stormwater runoff, flooding, and erosion 
6at the ground mounted solar energy system, improved soil 
7health, and increased foraging habitat for game birds, 
8songbirds, and pollinators, a county may (1) require a 
9commercial solar energy facility owner to plant, establish, 
10and maintain for the life of the facility vegetative ground 
11cover, consistent with the goals of the Pollinator-Friendly 
12Solar Site Act and (2) require the submittal of a vegetation 
13management plan that is in compliance with the agricultural 
14impact mitigation agreement in the application to construct 
15and operate a commercial solar energy facility in the county 
16if the vegetative ground cover and vegetation management plan 
17comply with the requirements of the underlying agreement with 
18the landowner or landowners where the facility will be 
19constructed. 
20    No later than 90 days after January 27, 2023 (the 
21effective date of Public Act 102-1123), the Illinois 
22Department of Natural Resources shall develop guidelines for 
23vegetation management plans that may be required under this 
24subsection for commercial solar energy facilities. The 
25guidelines must include guidance for short-term and long-term 
26property management practices that provide and maintain native 
 
 
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1and non-invasive naturalized perennial vegetation to protect 
2the health and well-being of pollinators. 
3    (s) If a facility owner enters into a road use agreement 
4with the Illinois Department of Transportation, a road 
5district, or other unit of local government relating to a 
6commercial wind energy facility or a commercial solar energy 
7facility, the road use agreement shall require the facility 
8owner to be responsible for (i) the reasonable cost of 
9improving roads used by the facility owner to construct the 
10commercial wind energy facility or the commercial solar energy 
11facility and (ii) the reasonable cost of repairing roads used 
12by the facility owner during construction of the commercial 
13wind energy facility or the commercial solar energy facility 
14so that those roads are in a condition that is safe for the 
15driving public after the completion of the facility's 
16construction. Roadways improved in preparation for and during 
17the construction of the commercial wind energy facility or 
18commercial solar energy facility shall be repaired and 
19restored to the improved condition at the reasonable cost of 
20the developer if the roadways have degraded or were damaged as 
21a result of construction-related activities.
22    The road use agreement shall not require the facility 
23owner to pay costs, fees, or charges for road work that is not 
24specifically and uniquely attributable to the construction of 
25the commercial wind energy facility or the commercial solar 
26energy facility. No road district or other unit of local 
 
 
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1government may request or require permit fees, fines, or other 
2payment obligations as a requirement for a road use agreement 
3with a facility owner unless the amount of the permit fee or 
4payment is equivalent to the amount of actual expenses 
5incurred by the road district or other unit of local 
6government for negotiating, executing, constructing, or 
7implementing the road use agreement. The road use agreement 
8shall not require any road work to be performed by or paid for 
9by the facility owner that is unrelated to the road 
10improvements required for the construction of the commercial 
11wind energy facility or the commercial solar energy facility 
12or the restoration of the roads used by the facility owner 
13during construction-related activities. Road-related fees, 
14permit fees, or other charges imposed by the Illinois 
15Department of Transportation, a road district, or other unit 
16of local government under a road use agreement with the 
17facility owner shall be reasonably related to the cost of 
18administration of the road use agreement.    
19    (s-5) The facility owner shall also compensate landowners 
20for crop losses or other agricultural damages resulting from 
21damage to the drainage system caused by the construction of 
22the commercial wind energy facility or the commercial solar 
23energy facility. The commercial wind energy facility owner or 
24commercial solar energy facility owner shall repair or pay for 
25the repair of all damage to the subsurface drainage system 
26caused by the construction of the commercial wind energy 
 
 
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1facility or the commercial solar energy facility in accordance 
2with the agriculture impact mitigation agreement requirements 
3for repair of drainage. The commercial wind energy facility 
4owner or commercial solar energy facility owner shall repair 
5or pay for the repair and restoration of surface drainage 
6caused by the construction or deconstruction of the commercial 
7wind energy facility or the commercial solar energy facility 
8as soon as reasonably practicable. 
9    (t) Notwithstanding any other provision of law, a facility 
10owner with siting approval from a county to construct a 
11commercial wind energy facility or a commercial solar energy 
12facility is authorized to cross or impact a drainage system, 
13including, but not limited to, drainage tiles, open drainage 
14ditches, culverts, and water gathering vaults, owned or under 
15the control of a drainage district under the Illinois Drainage 
16Code without obtaining prior agreement or approval from the 
17drainage district in accordance with the farmland drainage 
18plan required by subsection (j-5). 
19    (u) The amendments to this Section adopted in Public Act 
20102-1123 do not apply to: (1) an application for siting 
21approval or for a special use permit for a commercial wind 
22energy facility or commercial solar energy facility if the 
23application was submitted to a unit of local government before 
24January 27, 2023 (the effective date of Public Act 102-1123); 
25(2) a commercial wind energy facility or a commercial solar 
26energy facility if the facility owner has submitted an 
 
 
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1agricultural impact mitigation agreement to the Department of 
2Agriculture before January 27, 2023 (the effective date of 
3Public Act 102-1123); or (3) a commercial wind energy or 
4commercial solar energy development on property that is 
5located within an enterprise zone certified under the Illinois 
6Enterprise Zone Act, that was classified as industrial by the 
7appropriate zoning authority on or before January 27, 2023, 
8and that is located within 4 miles of the intersection of 
9Interstate 88 and Interstate 39. 
10(Source: P.A. 102-1123, eff. 1-27-23; 103-81, eff. 6-9-23; 
11103-580, eff. 12-8-23; revised 7-29-24.)
 
12    (55 ILCS 5/5-12024 new)
13    Sec. 5-12024. Energy storage systems.
14    (a) As used in this Section:
15    "Energy storage system" means a facility with an aggregate 
16energy capacity that is greater than 1,000 kilowatts and that 
17is capable of absorbing energy and storing it for use at a 
18later time, including, but not limited to, electrochemical and 
19electromechanical technologies. "Energy storage system" does 
20not include technologies that require combustion. "Energy 
21storage system" also does not include energy storage systems 
22associated with commercial solar energy facilities or 
23commercial wind energy facilities as defined in Section 
245-12020.
25    "Excused service interruption" means any period during 
 
 
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1which an energy storage system does not store or discharge 
2electricity and that is planned or reasonably foreseeable for 
3standard commercial operation, including any unavailability 
4caused by a buyer; storage capacity tests; system emergencies; 
5curtailments, including curtailment orders; transmission 
6system outages; compliance with any operating restriction; 
7serial defects; and planned outages.
8    "Facility owner" means (i) a person with a direct 
9ownership interest in an energy storage system, regardless of 
10whether the person is involved in acquiring the necessary 
11rights, permits, and approvals or otherwise planning for the 
12construction and operation of the facility and (ii) a person 
13who, at the time the facility is being developed, is acting as 
14a developer of the facility by acquiring the necessary rights, 
15permits, and approvals or by planning for the construction and 
16operation of the facility, regardless of whether the person 
17will own or operate the facility.
18    "Force majeure" means any event or circumstance that 
19delays or prevents an energy storage system from timely 
20performing all or a portion of its commercial operations if 
21the act or event, despite the exercise of commercially 
22reasonable efforts, cannot be avoided by and is beyond the 
23reasonable control, whether direct or indirect, of, and 
24without the fault or negligence of, a facility owner or 
25operator or any of its assignees. "Force majeure" includes, 
26but is not limited to:
 
 
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1        (1) fire, flood, tornado, or other natural disasters 
2    or acts of God;
3        (2) war, civil strife, terrorist attack, or other 
4    similar acts of violence;
5        (3) unavailability of materials, equipment, services, 
6    or labor, including unavailability due to global supply 
7    chain shortages;
8        (4) utility or energy shortages or acts or omissions 
9    of public utility providers;
10        (5) any delay resulting from a pandemic, epidemic, or 
11    other public health emergency or related restrictions; and
12        (6) litigation or a regulatory proceeding regarding a 
13    facility.
14    "NFPA" means the National Fire Protection Association.
15    "Nonparticipating property" means real property that is 
16not a participating property.
17    "Nonparticipating residence" means a residence that is 
18located on nonparticipating property and that exists and is 
19occupied on the date that the application for a permit to 
20develop an energy storage system is filed with the county.
21    "Occupied community building" means a school, place of 
22worship, day care facility, public library, or community 
23center that is occupied on the date that the application for a 
24permit to develop an energy storage system is filed with the 
25county in which the building is located.
26    "Participating property" means real property that is the 
 
 
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1subject of a written agreement between a facility owner and 
2the owner of the real property and that provides the facility 
3owner an easement, option, lease, or license to use the real 
4property for the purpose of constructing an energy storage 
5system or supporting facilities.
6    "Protected lands" means real property that is: (i) subject 
7to a permanent conservation right consistent with the Real 
8Property Conservation Rights Act; or (ii) registered or 
9designated as a nature preserve, buffer, or land and water 
10reserve under the Illinois Natural Areas Preservation Act.
11    "Supporting facilities" means the transmission lines, 
12substations, switchyard, access roads, meteorological towers, 
13storage containers, and equipment associated with the 
14generation, storage, and dispatch of electricity by an energy 
15storage system.
16    (b) Notwithstanding any other provision of law, if a 
17county has formed a zoning commission and adopted formal 
18zoning under Section 5-12007, then a county may establish 
19standards for energy storage systems in areas of the county 
20that are not within the zoning jurisdiction of a municipality. 
21The standards may include all of the requirements specified in 
22this Section but may not include requirements for energy 
23storage systems that are more restrictive than specified in 
24this Section or requirements that are not specified in this 
25Section.
26    (c) A county may require the energy storage facility to 
 
 
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1comply with the version of NFPA 855 "Standard for the 
2Installation of Stationary Energy Storage Systems" in effect 
3on the effective date of this amendatory Act or any successor 
4standard issued by the NFPA in effect on the date of siting or 
5special use permit approval. A county may not include 
6requirements for energy storage systems that are more 
7restrictive than NFPA 855 "Standard for the Installation of 
8Stationary Energy Storage Systems" unless required by this 
9Section.
10    (d) If a county has elected to establish standards under 
11subsection (b), then the zoning board of appeals for the 
12county shall hold at least one public hearing before the 
13county grants (i) siting approval or a special use permit for 
14an energy storage system or (ii) modification of an approved 
15siting or special use permit. The public hearing shall be 
16conducted in accordance with the Open Meetings Act and shall 
17conclude not more than 60 days after the filing of the 
18application for the facility. The county shall allow 
19interested parties to a special use permit an opportunity to 
20present evidence and to cross-examine witnesses at the 
21hearing, but the county may impose reasonable restrictions on 
22the public hearing, including reasonable time limitations on 
23the presentation of evidence and the cross-examination of 
24witnesses. The county shall also allow public comment at the 
25public hearing in accordance with the Open Meetings Act. The 
26county shall make its siting and permitting decisions not more 
 
 
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1than 30 days after the conclusion of the public hearing. 
2Notice of the hearing shall be published in a newspaper of 
3general circulation in the county.
4    (e) A county with an existing zoning ordinance in conflict 
5with this Section shall amend that zoning ordinance to comply 
6with this Section within 120 days after the effective date of 
7this amendatory Act of the 104th General Assembly.
8    (f) A county shall require an energy storage system to be 
9sited as follows, with setback distances measured from the 
10nearest edge of the nearest battery or other electrochemical 
11or electromechanical enclosure:
 
12Setback Description           Setback Distance
 
13Occupied Community            150 feet from the nearest 
14Buildings and                 point of the outside wall of
15Nonparticipating Residences   the occupied community building
16                              or nonparticipating residence
 
17Boundary Lines of             50 feet to the nearest point
18Occupied Community            on the property line of
19Buildings and                 the occupied community building
20Nonparticipating Residences   or nonparticipating property
 
21Public Road Rights-of-Way     50 feet from the nearest edge
22                              of the right-of-way
 
 
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1        (2) A county shall also require an energy storage 
2    system to be sited so that the facility's perimeter is 
3    enclosed by fencing having a height of at least 7 feet and 
4    no more than 25 feet.
5    This Section does not exempt or excuse compliance with 
6electric facility clearances approved or required by the 
7National Electrical Code, the National Electrical Safety Code, 
8the Illinois Commerce Commission, the Federal Energy 
9Regulatory Commission, and their designees or successors.
10    (g) A county may not set a sound limitation for energy 
11storage systems that is more restrictive than the sound 
12limitations established by the Illinois Pollution Control 
13Board under 35 Ill. Adm. Code Parts 900, 901, and 910. After 
14commercial operation, a county may require the facility owner 
15to provide, not more than once, octave band sound pressure 
16level measurements from a reasonable number of sampled 
17locations at the perimeter of the energy storage system to 
18demonstrate compliance with this Section.
19    (h) The provisions set forth in subsection (f) may be 
20waived subject to the written consent of the owner of each 
21affected nonparticipating property or nonparticipating 
22residence.
23    (i) A county may not place any restriction on the 
24installation or use of an energy storage system unless it has 
25formed a zoning commission and adopted formal zoning under 
26Section 5-12007 and adopts an ordinance that complies with 
 
 
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1this Section. A county may not establish siting standards for 
2supporting facilities that preclude development of an energy 
3storage system.
4    (j) A request for siting approval or a special use permit 
5for an energy storage system, or modification of an approved 
6siting approval or special use permit, shall be approved if 
7the request complies with the standards and conditions imposed 
8in this Code, the zoning ordinance adopted consistent with 
9this Section, and other State and federal statutes and 
10regulations. The siting approval or special use permit 
11approved by the county shall grant the facility owner a period 
12of at least 3 years after county approval to obtain a building 
13permit or commence construction of the energy storage system, 
14before the siting approval or special use permit may become 
15subject to revocation by the county. Facility owners may be 
16granted an extension on obtaining building permits or 
17commencing constructing upon a showing of good cause. A 
18facility owner's request for an extension may not be 
19unreasonably withheld, conditioned, or denied.
20    (k) A county may not adopt zoning regulations that 
21disallow, permanently or temporarily, an energy storage system 
22from being developed or operated in any district zones to 
23allow agricultural or industrial uses.
24    (l) A facility owner shall file a farmland drainage plan 
25with the county and impacted drainage districts that outlines 
26how surface and subsurface drainage of farmland will be 
 
 
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1restored during and following the construction or 
2deconstruction of the energy storage system. The plan shall be 
3created independently by the facility owner and shall include 
4the location of any potentially impacted drainage district 
5facilities to the extent the information is publicly available 
6from the county or the drainage district and plans to repair 
7any subsurface drainage affected during construction or 
8deconstruction using procedures outlined in the 
9decommissioning plan. All surface and subsurface damage shall 
10be repaired as soon as reasonably practicable.
11    (m) A facility owner shall compensate landowners for crop 
12losses or other agricultural damages resulting from damage to 
13a drainage system caused by the construction of an energy 
14storage system. The facility owner shall repair or pay for the 
15repair of all damage to the subsurface drainage system caused 
16by the construction of the energy storage system. The facility 
17owner shall repair or pay for the repair and restoration of 
18surface drainage caused by the construction or deconstruction 
19of the energy storage facility as soon as reasonably 
20practicable.    
21    (n) County siting approval or special use permit 
22application fees for an energy storage system shall not exceed 
23the lesser of (i) $5,000 per each megawatt of nameplate 
24capacity of the energy storage system or (ii) $50,000.
25    (o) The county may require a facility owner to provide a 
26decommissioning plan to the county. The decommissioning plan 
 
 
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1may include all requirements for decommissioning plans in NFPA 
2855 and may also require the facility owner to:
3        (1) state how the energy storage system will be 
4    decommissioned, including removal to a depth of 3 feet of 
5    all structures that have no ongoing purpose and all debris 
6    and restoration of the soil and any vegetation to a 
7    condition as close as reasonably practicable to the soil's 
8    and vegetation's preconstruction condition within 18 
9    months of the end of project life or facility abandonment;
10        (2) include provisions related to commercially 
11    reasonable efforts to reuse or recycle of equipment and 
12    components associated with the commercial offsite energy 
13    storage system;
14        (3) include financial assurance in the form of a 
15    reclamation or surety bond or other commercially available 
16    financial assurance that is acceptable to the county, with 
17    the county or participating property owner as beneficiary. 
18    The amount of the financial assurance shall not be more 
19    than the estimated cost of decommissioning the energy 
20    facility, after deducting salvage value, as calculated by 
21    a professional engineer licensed to practice engineering 
22    in this State with expertise in preparing decommissioning 
23    estimates, retained by the applicant. The financial 
24    assurance shall be provided to the county incrementally as 
25    follows:
26            (A) 25% before the start of full commercial 
 
 
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1        operation;
2            (B) 50% before the start of the 5th year of 
3        commercial operation; and
4            (C) 100% by the start of the tenth year of 
5        commercial operation;
6        (4) update the amount of the financial assurance not 
7    more than every 5 years for the duration of commercial 
8    operations. The amount shall be calculated by a 
9    professional engineer licensed to practice engineering in 
10    this State with expertise in decommissioning, hired by the 
11    facility owner; and
12        (5) decommission the energy storage system, in 
13    accordance with an approved decommissioning plan, within 
14    18 months after abandonment. An energy storage system that 
15    has not stored electrical energy for 12 consecutive months 
16    or that fails, for a period of 6 consecutive months, to pay 
17    a property owner who is party to a written agreement, 
18    including, but not limited to, an easement, option, lease, 
19    or license under the terms of which an energy storage 
20    system is constructed on the property, amounts owed in 
21    accordance with the written agreement shall be considered 
22    abandoned, except when the inability to store energy is 
23    the result of an event of force majeure or excused service 
24    interruption.
25    (p) A county may not condition approval of an energy 
26storage system on a property value guarantee and may not 
 
 
10400SB0025ham002- 422 -LRB104 07069 AAS 28576 a

1require a facility owner to pay into a neighboring property 
2devaluation escrow account.
3    (q) A county may require that a facility owner provide:
4        (1) the results and recommendations from consultation 
5    with the Department of Natural Resources that are obtained 
6    through the Ecological Compliance Assessment Tool (EcoCAT) 
7    or a comparable successor tool; and
8        (2) the results of the United States Fish and Wildlife 
9    Service's Information for Planning and Consulting or a 
10    comparable successor tool.
11    (r) A county may require an energy storage system to 
12adhere to the recommendations provided by the Department of 
13Natural Resources in an Agency Action Report under 17 Ill. 
14Admin. Code 1075.
15    (s) A county may require a facility owner to:
16        (1) demonstrate avoidance of protected lands as 
17    identified by the Department of Natural Resources and the 
18    Illinois Nature Preserves Commission; or
19        (2) consider the recommendations of the Department of 
20    Natural Resources for setbacks from protected lands, 
21    including areas identified by the Illinois Nature 
22    Preserves Commission.
23    (t) A county may require that a facility owner provide 
24evidence of consultation with the Illinois Historic 
25Preservation Division to assess potential impacts on 
26State-registered historic sites under the Illinois State 
 
 
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1Agency Historic Resources Preservation Act.
2    (u) A county may require that an application for siting 
3approval or special use permit include the following 
4information on a site plan:
5        (1) a description of the property lines and physical 
6    features, including roads, for the facility site;
7        (2) a description of the proposed changes to the 
8    landscape of the facility site, including vegetation 
9    clearing and planting, exterior lighting, and screening or 
10    structures; and
11        (3) a description of the zoning district designation 
12    for the parcel of land comprising the facility site.
13    (v) A county may not prohibit an energy storage system 
14from undertaking periodic augmentation to maintain the 
15approximate original capacity of the energy storage system. A 
16county may not require renewed or additional siting approval 
17or special use permit approval of periodic augmentation to 
18maintain the approximate original capacity of the energy 
19storage system.
20    (w) A county that issues a building permit for energy 
21storage systems shall review and process building permit 
22applications within 60 days after receipt of the building 
23permit application. If a county does not grant or deny the 
24building permit application within 60 days, the building 
25permit shall be deemed granted. If a county denies a building 
26permit application, it shall specify the reason for the denial 
 
 
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1in writing as part of its denial.
2    (x) A county may require a single building permit and 
3permit fee for the facility which includes all supporting 
4facilities. A county building permit fee for an energy storage 
5system shall not exceed the lesser of (i) $5,000 per each 
6megawatt of nameplate capacity of the energy storage system or 
7(ii) $50,000. A county may require that the application for 
8building permit contain:
9        (1) an electrical diagram detailing the battery energy 
10    storage system layout, associated components, and 
11    electrical interconnection methods, with all National 
12    Electrical Code compliant disconnects and overcurrent 
13    devices; and
14        (2) an equipment specification sheet.
15    (y) A county may require the facility owner to submit to 
16the county prior to the facility's commercial operation a 
17commissioning report meeting the requirements of NFPA 855 
18Sections 4.2.4, 6.1.3, and 6.1.5.5, as published in 2023, or 
19the applicable Sections in the most recent version of NFPA 
20855.
21    (z) A county may require the facility owner to submit to 
22the county prior to the facility's commercial operation a 
23hazard mitigation analysis meeting the requirements of NFPA 
24855 Section 4.4 or the applicable Sections in the most recent 
25version of NFPA 855.
26    (aa) A county may require the facility owner to submit to 
 
 
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1the county an emergency operations plan meeting the 
2requirements of NFPA 855 Section 4.3.2.1.4, published in 2023, 
3or applicable Sections in the most recent version of NFPA 855, 
4prior to commercial operation.
5    (bb) A county may require a warning that complies with 
6requirements in NFPA 855 Section 4.7.4, published in 2023, or 
7applicable sections in the most recent version of NFPA 855.
8    (cc) A county may require the energy storage system to 
9adhere to the principles for responsible outdoor lighting 
10provided by the International Dark-Sky Association and shall 
11limit outdoor lighting to that which is minimally required for 
12safety and operational purposes. Any outdoor lighting shall be 
13reasonably shielded and downcast from all residences and 
14adjacent properties.
15    (dd) This Section does not exempt compliance with fire and 
16safety standards and guidance established for the installation 
17of lithium-ion battery energy storage systems set by the NFPA.
18    (ee) Prior to commencement of commercial operation, the 
19facility owner shall offer to provide training for local fire 
20departments and emergency responders in accordance with the 
21facility emergency operations plan. A copy of the emergency 
22operations plan shall be given to the facility owner, the 
23local fire department, and emergency responders. All batteries 
24integrated within an energy storage system shall be listed 
25under the UL 1973 Standard. All batteries integrated within an 
26energy storage system shall be listed in accordance with UL 
 
 
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19540 Standard, either from the manufacturer or by a field 
2evaluation.
3    (ff) If a facility owner enters into a road use agreement 
4with the Department of Transportation, a road district, or 
5other unit of local government relating to an energy storage 
6system, then the road use agreement shall require the facility 
7owner to be responsible for (i) the reasonable cost of 
8improving, if necessary, roads used by the facility owner to 
9construct the energy storage system and (ii) the reasonable 
10cost of repairing roads used by the facility owner during 
11construction of the energy storage system so that those roads 
12are in a condition that is safe for the driving public after 
13the completion of the facility's construction. A roadway 
14improved in preparation for and during the construction of the 
15energy storage system shall be repaired and restored to the 
16improved condition at the reasonable cost of the developer if 
17the roadways have degraded or were damaged as a result of 
18construction-related activities.
19    The road use agreement shall not require the facility 
20owner to pay costs, fees, or charges for road work that is not 
21specifically and uniquely attributable to the construction of 
22the energy storage system. No road district or other unit of 
23local government may request or require a fine, permit fee, or 
24other payment obligation as a requirement for a road use 
25agreement with a facility owner unless the amount of the fine, 
26permit fee, or other payment obligation is equivalent to the 
 
 
10400SB0025ham002- 427 -LRB104 07069 AAS 28576 a

1amount of actual expenses incurred by the road district or 
2other unit of local government for negotiating, executing, 
3constructing, or implementing the road use agreement. The road 
4use agreement shall not require the facility owner to perform 
5or pay for any road work that is unrelated to the road 
6improvements required for the construction of the commercial 
7wind energy facility or the commercial solar energy facility 
8or the restoration of the roads used by the facility owner 
9during construction-related activities.
10    (gg) The provisions of this amendatory Act of the 104th 
11General Assembly do not apply to an application for siting 
12approval or special use permit for an energy storage system if 
13the application was submitted to a county before the effective 
14date of this amendatory Act of the 104th General Assembly.
 
15    (55 ILCS 5/Art. 5 Div. 5-46 heading new)
16
Division 5-46.  Solar Bill of Rights

 
17    (55 ILCS 5/5-46005 new)
18    Sec. 5-46005. Definitions. As used in this Division:
19    "Low-voltage solar-powered device" means a piece of 
20equipment designed for a particular purpose, including, but 
21not limited to, doorbells, security systems, and illumination 
22equipment, powered by a solar collector operating at less than 
2350 volts, and located:
24        (1) entirely within the lot or parcel owned by the 
 
 
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1    property owner; or
2        (2) within a common area without being permanently 
3    attached to common property.
4    "Solar collector" means:
5        (1) an assembly, structure, or design, including 
6    passive elements, used for gathering, concentrating, or 
7    absorbing direct and indirect solar energy and specially 
8    designed for holding a substantial amount of useful 
9    thermal energy and to transfer that energy to a gas, 
10    solid, or liquid or to use that energy directly;
11        (2) a mechanism that absorbs solar energy and converts 
12    it into electricity;
13        (3) a mechanism or process used for gathering solar 
14    energy through wind or thermal gradients; or
15        (4) a component used to transfer thermal energy to a 
16    gas, solid, or liquid, or to convert it into electricity.
17    "Solar energy" means radiant energy received from the sun 
18at wavelengths suitable for heat transfer, photosynthetic use, 
19or photovoltaic use.
20    "Solar energy system" means:
21        (1) a complete assembly, structure, or design of a 
22    solar collector or a solar storage mechanism that uses 
23    solar energy for generating electricity or for heating or 
24    cooling gases, solids, liquids, or other materials; and
25        (2) the design, materials, or elements of a system and 
26    its maintenance, operation, and labor components, and the 
 
 
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1    necessary components, if any, of supplemental conventional 
2    energy systems designed or constructed to interface with a 
3    solar energy system.
4    "Solar storage mechanism" means equipment or elements, 
5such as piping and transfer mechanisms, containers, heat 
6exchangers, batteries, or controls thereof and gases, solids, 
7liquids, or combinations thereof, that are utilized for 
8storing solar energy, gathered by a solar collector, for 
9subsequent use.
 
10    (55 ILCS 5/5-46010 new)
11    Sec. 5-46010. Prohibitions. Notwithstanding any provision 
12of this Code or other provision of law, the adoption of any 
13ordinance or resolution or the exercise of any power by a 
14county that prohibits or has the effect of prohibiting the 
15installation of a solar energy system or low-voltage 
16solar-powered devices is expressly prohibited.
 
17    (55 ILCS 5/5-46020 new)
18    Sec. 5-46020. Costs; attorney's fees. In any litigation 
19arising under this Division or involving the application of 
20this Division, the prevailing party shall be entitled to costs 
21and reasonable attorney's fees.
 
22    (55 ILCS 5/5-46025 new)
23    Sec. 5-46025. Applicability.
 
 
10400SB0025ham002- 430 -LRB104 07069 AAS 28576 a

1    (a) As used in this Section, "shared roof" means any roof 
2that (i) serves more than one unit, including, but not limited 
3to, a contiguous roof serving adjacent units, or (ii) is part 
4of the common elements or common area of a unit.
5    (b) This Division shall not apply to any building that:
6        (1) is greater than 60 feet in height; or (2) has a 
7    shared roof and is subject to a homeowners' association, 
8    common interest community association, or condominium unit 
9    owners' association. (b) Notwithstanding subsection (a) of 
10    this Section, this Division shall apply to any building 
11    with a shared roof: (1) where the solar energy system is 
12    located entirely within that portion of the shared roof 
13    owned and maintained by the property owner;
14        (2) where all property owners sharing the shared roof 
15    are in agreement to install a solar energy system; or
16        (3) to the extent this Division applies to low-voltage 
17    solar-powered devices.
18    (c) Notwithstanding subsection (b) of this Section, this 
19Division shall apply to any building with a shared roof:
20        (1) where the solar energy system is located entirely 
21    within that portion of the shared roof owned and 
22    maintained by the property owner;
23        (2) where all property owners sharing the shared roof 
24    are in agreement to install a solar energy system; or
25        (3) to the extent this Division applies to low-voltage 
26    solar-powered devices.    
 
 
 
10400SB0025ham002- 431 -LRB104 07069 AAS 28576 a

1    Section 90-30. The Illinois Municipal Code is amended by 
2adding Division 15.5 as follows:
 
3    (65 ILCS 5/Art. 11 Div. 15.5 heading new)
4
Division 15.5.  Solar Bill of Rights

 
5    (65 ILCS 5/11-15.5-5 new)
6    Sec. 11-15.5-5. Definitions. As used in this Division:
7    "Low-voltage solar-powered device" means a piece of 
8equipment designed for a particular purpose, including, but 
9not limited to, doorbells, security systems, and illumination 
10equipment, powered by a solar collector operating at less than 
1150 volts, and located:
12        (1) entirely within the lot or parcel owned by the 
13    property owner; or
14        (2) within a common area without being permanently 
15    attached to common property.
16    "Solar collector" means:
17        (1) an assembly, structure, or design, including 
18    passive elements, used for gathering, concentrating, or 
19    absorbing direct and indirect solar energy and specially 
20    designed for holding a substantial amount of useful 
21    thermal energy and to transfer that energy to a gas, 
22    solid, or liquid or to use that energy directly;
23        (2) a mechanism that absorbs solar energy and converts 
 
 
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1    it into electricity;
2        (3) a mechanism or process used for gathering solar 
3    energy through wind or thermal gradients; or
4        (4) a component used to transfer thermal energy to a 
5    gas, solid, or liquid, or to convert it into electricity.
6    "Solar energy" means radiant energy received from the sun 
7at wavelengths suitable for heat transfer, photosynthetic use, 
8or photovoltaic use.
9    "Solar energy system" means:
10        (1) a complete assembly, structure, or design of a 
11    solar collector or a solar storage mechanism that uses 
12    solar energy for generating electricity or for heating or 
13    cooling gases, solids, liquids, or other materials; and
14        (2) the design, materials, or elements of a system and 
15    its maintenance, operation, and labor components, and the 
16    necessary components, if any, of supplemental conventional 
17    energy systems designed or constructed to interface with a 
18    solar energy system.
19    "Solar storage mechanism" means equipment or elements, 
20such as piping and transfer mechanisms, containers, heat 
21exchangers, batteries, or controls thereof and gases, solids, 
22liquids, or combinations thereof, that are utilized for 
23storing solar energy, gathered by a solar collector, for 
24subsequent use.
 
25    (65 ILCS 5/11-15.5-10 new)
 
 
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1    Sec. 11-15.5-10. Prohibitions. Notwithstanding any 
2provision of this Code or other provision of law, the adoption 
3of any ordinance or resolution or the exercise of any power, by 
4municipality that prohibits or has the effect of prohibiting 
5the installation of a solar energy system or low-voltage 
6solar-powered devices is expressly prohibited. Municipalities 
7that own local electric distribution systems may adopt and 
8implement reasonable policies, consistent with Section 17-900 
9of the Public Utilities Act, regarding the interconnection and 
10use of solar energy systems.
 
11    (65 ILCS 5/11-15.5-20 new)
12    Sec. 11-15.5-20. Costs; attorney's fees. In any litigation 
13arising under this Division or involving the application of 
14this Division, the prevailing party shall be entitled to costs 
15and reasonable attorney's fees.
 
16    (65 ILCS 5/11-15.5-25 new)
17    Sec. 11-15.5-25. Applicability.
18    (a) As used in this Section, "shared roof" means any roof 
19that (i) serves more than one unit, including, but not limited 
20to, a contiguous roof serving adjacent units, or (ii) is part 
21of the common elements or common area of a unit.
22    (b) This Division shall not apply to any building that:
23        (1) is greater than 60 feet in height; or
24        (2) has a shared roof and is subject to a homeowners' 
 
 
10400SB0025ham002- 434 -LRB104 07069 AAS 28576 a

1    association, common interest community association, or 
2    condominium unit owners' association.
3    (c) Notwithstanding subsection (b) of this Section, this 
4Division shall apply to any building with a shared roof:
5        (1) where the solar energy system is located entirely 
6    within that portion of the shared roof owned and 
7    maintained by the property owner;
8        (2) where all property owners sharing the shared roof 
9    are in agreement to install a solar energy system; or
10        (3) to the extent this Division applies to low-voltage 
11    solar-powered devices.
 
12    Section 90-35. The Public Utilities Act is amended by 
13changing Sections 7-102, 8-103B, 8-406, 8-512, 9-229, 
1416-107.5, 16-107.6, 16-108, 16-108.19, 16-108.30, 16-111.5, 
1516-111.7, 16-115A, 16-119A, and 17-900 and by adding Sections 
168-101.1, 8-513, 16-107.8, 16-107.9, 16-126.2, 16-145, 16-201, 
1716-202, 20-140, and 20-145 as follows:
 
18    (220 ILCS 5/7-102)  (from Ch. 111 2/3, par. 7-102)
19    Sec. 7-102. Transactions requiring Commission approval. 
20    (A) Unless the consent and approval of the Commission is 
21first obtained or unless such approval is waived by the 
22Commission or is exempted in accordance with the provisions of 
23this Section or of any other Section of this Act:    
24        (a) No 2 or more public utilities may enter into 
 
 
10400SB0025ham002- 435 -LRB104 07069 AAS 28576 a

1    contracts with each other that will enable such public 
2    utilities to operate their lines or plants in connection 
3    with each other.    
4        (b) No public utility may purchase, lease, or in any 
5    other manner acquire control, direct or indirect, over the 
6    franchises, licenses, permits, plants, equipment, business 
7    or other property of any other public utility.    
8        (c) No public utility may assign, transfer, lease, 
9    mortgage, sell (by option or otherwise), or otherwise 
10    dispose of or encumber the whole or any part of its 
11    franchises, licenses, permits, plant, equipment, business, 
12    or other property, but the consent and approval of the 
13    Commission shall not be required for the sale, lease, 
14    assignment or transfer (1) by any public utility of any 
15    tangible personal property which is not necessary or 
16    useful in the performance of its duties to the public, or    
17    (2) by any electric utility, as defined by Section 16-105, 
18    of functional control to a regional transmission operator, 
19    as defined in Section 16-126, of facilities operating at 
20    69,000 volts and that would otherwise qualify for such 
21    transfer under the applicable rules of the regional 
22    transmission operator taking functional control, or (3) by 
23    any railroad of any real or tangible personal property.    
24        (d) No public utility may by any means, direct or 
25    indirect, merge or consolidate its franchises, licenses, 
26    permits, plants, equipment, business or other property 
 
 
10400SB0025ham002- 436 -LRB104 07069 AAS 28576 a

1    with that of any other public utility.    
2        (e) No public utility may purchase, acquire, take or 
3    receive any stock, stock certificates, bonds, notes or 
4    other evidences of indebtedness of any other public 
5    utility.    
6        (f) No public utility may in any manner, directly or 
7    indirectly, guarantee the performance of any contract or 
8    other obligation of any other person, firm or corporation 
9    whatsoever.    
10        (g) No public utility may use, appropriate, or divert 
11    any of its moneys, property or other resources in or to any 
12    business or enterprise which is not, prior to such use, 
13    appropriation or diversion essentially and directly 
14    connected with or a proper and necessary department or 
15    division of the business of such public utility; provided 
16    that this subsection shall not be construed as modifying 
17    subsections (a) through (e) of this Section.    
18        (h) No public utility may, directly or indirectly, 
19    invest, loan or advance, or permit to be invested, loaned 
20    or advanced any of its moneys, property or other resources 
21    in, for, in behalf of or to any other person, firm, trust, 
22    group, association, company or corporation whatsoever, 
23    except that no consent or approval by the Commission is 
24    necessary for the purchase of stock in development credit 
25    corporations organized under the Illinois Development 
26    Credit Corporation Act, providing that no such purchase 
 
 
10400SB0025ham002- 437 -LRB104 07069 AAS 28576 a

1    may be made hereunder if, as a result of such purchase, the 
2    cumulative purchase price of all such shares owned by the 
3    utility would exceed one-fiftieth of one per cent of the 
4    utility's gross operating revenue for the preceding 
5    calendar year.
6    (B) Any public utility may present to the Commission for 
7approval options or contracts to sell or lease real property, 
8notwithstanding that the value of the property under option 
9may have changed between the date of the option and the 
10subsequent date of sale or lease. If the options or contracts 
11are approved by the Commission, subsequent sales or leases in 
12conformance with those options or contracts may be made by the 
13public utility without any further action by the Commission. 
14If approval of the options or contracts is denied by the 
15Commission, the options or contracts are void and any 
16consideration theretofore paid to the public utility must be 
17refunded within 30 days following disapproval of the 
18application.
19    (C) The proceedings for obtaining the approval of the 
20Commission provided for in this Section shall be as follows: 
21There shall be filed with the Commission a petition, joint or 
22otherwise, as the case may be, signed and verified by the 
23president, any vice president, secretary, treasurer, 
24comptroller, general manager, or chief engineer of the 
25respective companies, or by the person or company, as the case 
26may be, clearly setting forth the object and purposes desired, 
 
 
10400SB0025ham002- 438 -LRB104 07069 AAS 28576 a

1and setting forth the full and complete terms of the proposed 
2assignment, transfer, lease, mortgage, purchase, sale, merger, 
3consolidation, contract or other transaction, as the case may 
4be. Upon the filing of such petition, the Commission shall, if 
5it deems necessary, fix a time and place for the hearing 
6thereon. After such hearing, or in case no hearing is 
7required, if the Commission is satisfied that such petition 
8should reasonably be granted, and that the public will be 
9convenienced thereby, the Commission shall make such order in 
10the premises as it may deem proper and as the circumstances may 
11require, attaching such conditions as it may deem proper, and 
12thereupon it shall be lawful to do the things provided for in 
13such order. The Commission shall impose such conditions as 
14will protect the interest of minority and preferred 
15stockholders.
16    (D) The Commission shall have power by general rules 
17applicable alike to all public utilities, other than electric 
18and gas public utilities, affected thereby to waive the filing 
19and necessity for approval of the following: (a) sales of 
20property involving a consideration of not more than $300,000 
21for utilities with gross revenues in excess of $50,000,000 
22annually and a consideration of not more than $100,000 for all 
23other utilities; (b) leases, easements and licenses involving 
24a consideration or rental of not more than $30,000 per year for 
25utilities with gross revenues in excess of $50,000,000 
26annually and a consideration or rental of not more than 
 
 
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1$10,000 per year for all other utilities; (c) leases of office 
2building space not required by the public utility in rendering 
3service to the public; (d) the temporary leasing, lending or 
4interchanging of equipment in the ordinary course of business 
5or in case of an emergency; and (e) purchase-money mortgages 
6given by a public utility in connection with the purchase of 
7tangible personal property where the total obligation to be 
8secured shall be payable within a period not exceeding one 
9year. However, if the Commission, after a hearing, finds that 
10any public utility to which such rule is applicable is abusing 
11or has abused such general rule and thereby is evading 
12compliance with the standard established herein, the 
13Commission shall have power to require such public utility to 
14thereafter file and receive the Commission's approval upon all 
15such transactions as described in this Section, but such 
16general rule shall remain in full force and effect as to all 
17other public utilities to which such rule is applicable.
18    (E) The filing of, and the consent and approval of the 
19Commission for, any assignment, transfer, lease, mortgage, 
20purchase, sale, merger, consolidation, contract or other 
21transaction by an electric or gas public utility with gross 
22revenues in all jurisdictions of $250,000,000 or more annually 
23involving a sale price or annual consideration in an amount of 
24$5,000,000 or less shall not be required. The Commission shall 
25also have the authority, on petition by an electric or gas 
26public utility with gross revenues in all jurisdictions of 
 
 
10400SB0025ham002- 440 -LRB104 07069 AAS 28576 a

1$250,000,000 or more annually, to establish by order higher 
2thresholds than the foregoing for the requirement of approval 
3of transactions by the Commission pursuant to this Section for 
4the electric or gas public utility, but no greater than 1% of 
5the electric or gas public utility's average total gross 
6utility plant in service in the case of sale, assignment or 
7acquisition of property, or 2.5% of the electric or gas public 
8utility's total revenue in the case of other sales price or 
9annual consideration, in each case based on the preceding 
10calendar year, and subject to the power of the Commission, 
11after notice and hearing, to further revise those thresholds 
12at a later date. In addition to the foregoing, the Commission 
13shall have power by general rules applicable alike to all 
14electric and gas public utilities affected thereby to waive 
15the filing and necessity for approval of the following: (a) 
16sales of property involving a consideration of $100,000 or 
17less for electric and gas utilities with gross revenues in all 
18jurisdictions of less than $250,000,000 annually; (b) leases, 
19easements and licenses involving a consideration or rental of 
20not more than $10,000 per year for electric and gas utilities 
21with gross revenues in all jurisdictions of less than 
22$250,000,000 annually; (c) leases of office building space not 
23required by the electric or gas public utility in rendering 
24service to the public; (d) the temporary leasing, lending or 
25interchanging of equipment in the ordinary course of business 
26or in the case of an emergency; and (e) purchase-money 
 
 
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1mortgages given by an electric or gas public utility in 
2connection with the purchase of tangible personal property 
3where the total obligation to be secured shall be payable 
4within a period of one year or less. However, if the 
5Commission, after a hearing, finds that any electric or gas 
6public utility is abusing or has abused such general rule and 
7thereby is evading compliance with the standard established 
8herein, the Commission shall have power to require such 
9electric or gas public utility to thereafter file and receive 
10the Commission's approval upon all such transactions as 
11described in this Section and not exempted pursuant to the 
12first sentence of this paragraph or to subsection (g) of 
13Section 16-111 of this Act, but such general rule shall remain 
14in full force and effect as to all other electric and gas 
15public utilities.
16    Every assignment, transfer, lease, mortgage, sale or other 
17disposition or encumbrance of the whole or any part of the 
18franchises, licenses, permits, plant, equipment, business or 
19other property of any public utility, or any merger or 
20consolidation thereof, and every contract, purchase of stock, 
21or other transaction referred to in this Section and not 
22exempted in accordance with the provisions of the immediately 
23preceding paragraph of this Section, made otherwise than in 
24accordance with an order of the Commission authorizing the 
25same, except as provided in this Section, shall be void. The 
26provisions of this Section shall not apply to any transactions 
 
 
10400SB0025ham002- 442 -LRB104 07069 AAS 28576 a

1by or with a political subdivision or municipal corporation of 
2this State.
3    (F) The provisions of this Section do not apply to the 
4purchase or sale of emission allowances created under and 
5defined in Title IV of the federal Clean Air Act Amendments of 
61990 (P.L. 101-549), as amended.
7(Source: P.A. 90-561, eff. 12-16-97; 91-357, eff. 7-29-99.)
 
8    (220 ILCS 5/8-101.1 new)
9    Sec. 8-101.1. Duties of public utilities; labor force.
10    (a) As used in this Section:
11    "Labor force" means the employees hired directly by the 
12utility and all employees of any and all suppliers and 
13subcontractors of the utility tasked with the construction, 
14maintenance and repair of such utility's infrastructure.
15    "Public utility" means a public utility, as defined in 
16Section 3-105 of this Act, serving more than 100,000 customers 
17as of January 1, 2025.
18    "Substantial change in labor force" means either (1) a 
19greater than 5% reduction in the total labor force or (2) more 
20than a 5% decrease in the ratio of labor force spending 
21compared to capital spending.
22    (b) A public utility shall ensure that it has the 
23necessary labor force in order to furnish, provide, and 
24maintain such service instrumentalities, equipment, and 
25facilities to promote the safety, health, comfort, and 
 
 
10400SB0025ham002- 443 -LRB104 07069 AAS 28576 a

1convenience of its patrons, employees, and the public and to 
2be in all respects adequate, efficient, just, and reasonable.
3    (c) Unless the Commission specifically orders and except 
4as otherwise provided in this Section, no substantial change 
5shall be made by any public utility in its labor force unless 
6the public utility provides notice to the Commission at least 
745 days before the implementation of the change. A public 
8utility shall include a report with its notice that provides 
9the following:
10        (1) a detailed analysis and explanation of how and why 
11    a change in a specific law, regulation, or market factor 
12    requires the public utility to make the substantial change 
13    in its labor force; and
14        (2) whether the substantial change in the public 
15    utility's labor force, at a minimum:
16            (i) is in the public interest;
17            (ii) will not endanger the quality and 
18        availability of public utility services;
19            (iii) will not have a negative impact on the 
20        safety or reliability of public utility services; and
21            (iv) is designed to minimize the financial 
22        hardship on the members of its labor force impacted by 
23        the substantial change.
 
24    (220 ILCS 5/8-103B)
25    Sec. 8-103B. Energy efficiency and demand-response 
 
 
10400SB0025ham002- 444 -LRB104 07069 AAS 28576 a

1measures.
2    (a) It is the policy of the State that electric utilities 
3are required to use cost-effective energy efficiency and 
4demand-response measures to reduce delivery load. Requiring 
5investment in cost-effective energy efficiency and 
6demand-response measures will reduce direct and indirect costs 
7to consumers by decreasing environmental impacts and by 
8avoiding or delaying the need for new generation, 
9transmission, and distribution infrastructure. It serves the 
10public interest to allow electric utilities to recover costs 
11for reasonably and prudently incurred expenditures for energy 
12efficiency and demand-response measures. As used in this 
13Section, "cost-effective" means that the measures satisfy the 
14total resource cost test. The low-income measures described in 
15subsection (c) of this Section shall not be required to meet 
16the total resource cost test. For purposes of this Section, 
17the terms "energy-efficiency", "demand-response", "electric 
18utility", and "total resource cost test" have the meanings set 
19forth in the Illinois Power Agency Act. "Black, indigenous, 
20and people of color" and "BIPOC" means people who are members 
21of the groups described in subparagraphs (a) through (e) of 
22paragraph (A) of subsection (1) of Section 2 of the Business 
23Enterprise for Minorities, Women, and Persons with 
24Disabilities Act. 
25    (a-5) This Section applies to electric utilities serving 
26more than 500,000 retail customers in the State for those 
 
 
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1multi-year plans commencing after December 31, 2017. 
2    (b) For purposes of this Section, through calendar year 
32026, electric utilities subject to this Section that serve 
4more than 3,000,000 retail customers in the State shall be 
5deemed to have achieved a cumulative persisting annual savings 
6of 6.6% from energy efficiency measures and programs 
7implemented during the period beginning January 1, 2012 and 
8ending December 31, 2017, which percent is based on the deemed 
9average weather normalized sales of electric power and energy 
10during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. 
11For the purposes of this subsection (b) and subsection (b-5), 
12the 88,000,000 MWhs of deemed electric power and energy sales 
13shall be reduced by the number of MWhs equal to the sum of the 
14annual consumption of customers that have opted out of 
15subsections (a) through (j) of this Section under paragraph 
16(1) of subsection (l) of this Section, as averaged across the 
17calendar years 2014, 2015, and 2016. After 2017, the deemed 
18value of cumulative persisting annual savings from energy 
19efficiency measures and programs implemented during the period 
20beginning January 1, 2012 and ending December 31, 2017, shall 
21be reduced each year, as follows, and the applicable value 
22shall be applied to and count toward the utility's achievement 
23of the cumulative persisting annual savings goals set forth in 
24subsection (b-5):
25        (1) 5.8% deemed cumulative persisting annual savings 
26    for the year ending December 31, 2018;
 
 
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1        (2) 5.2% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2019;
3        (3) 4.5% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2020;
5        (4) 4.0% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2021;
7        (5) 3.5% deemed cumulative persisting annual savings 
8    for the year ending December 31, 2022;
9        (6) 3.1% deemed cumulative persisting annual savings 
10    for the year ending December 31, 2023;
11        (7) 2.8% deemed cumulative persisting annual savings 
12    for the year ending December 31, 2024;
13        (8) 2.5% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2025; and    
15        (9) 2.3% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2026. ;
17        (10) 2.1% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2027;
19        (11) 1.8% deemed cumulative persisting annual savings 
20    for the year ending December 31, 2028;
21        (12) 1.7% deemed cumulative persisting annual savings 
22    for the year ending December 31, 2029;
23        (13) 1.5% deemed cumulative persisting annual savings 
24    for the year ending December 31, 2030;
25        (14) 1.3% deemed cumulative persisting annual savings 
26    for the year ending December 31, 2031;
 
 
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1        (15) 1.1% deemed cumulative persisting annual savings 
2    for the year ending December 31, 2032;
3        (16) 0.9% deemed cumulative persisting annual savings 
4    for the year ending December 31, 2033;
5        (17) 0.7% deemed cumulative persisting annual savings 
6    for the year ending December 31, 2034;
7        (18) 0.5% deemed cumulative persisting annual savings 
8    for the year ending December 31, 2035;
9        (19) 0.4% deemed cumulative persisting annual savings 
10    for the year ending December 31, 2036;
11        (20) 0.3% deemed cumulative persisting annual savings 
12    for the year ending December 31, 2037;
13        (21) 0.2% deemed cumulative persisting annual savings 
14    for the year ending December 31, 2038;
15        (22) 0.1% deemed cumulative persisting annual savings 
16    for the year ending December 31, 2039; and
17        (23) 0.0% deemed cumulative persisting annual savings 
18    for the year ending December 31, 2040 and all subsequent 
19    years.    
20    For purposes of this Section, "cumulative persisting 
21annual savings" means the total electric energy savings in a 
22given year from measures installed in that year or in previous 
23years, but no earlier than January 1, 2012, that are still 
24operational and providing savings in that year because the 
25measures have not yet reached the end of their useful lives.
26    (b-5) Beginning in 2018 and through calendar year 2026, 
 
 
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1electric utilities subject to this Section that serve more 
2than 3,000,000 retail customers in the State shall achieve the 
3following cumulative persisting annual savings goals, as 
4modified by subsection (f) of this Section and as compared to 
5the deemed baseline of 88,000,000 MWhs of electric power and 
6energy sales set forth in subsection (b), as reduced by the 
7number of MWhs equal to the sum of the annual consumption of 
8customers that have opted out of subsections (a) through (j) 
9of this Section under paragraph (1) of subsection (l) of this 
10Section as averaged across the calendar years 2014, 2015, and 
112016, through the implementation of energy efficiency measures 
12during the applicable year and in prior years, but no earlier 
13than January 1, 2012:
14        (1) 7.8% cumulative persisting annual savings for the 
15    year ending December 31, 2018;
16        (2) 9.1% cumulative persisting annual savings for the 
17    year ending December 31, 2019;
18        (3) 10.4% cumulative persisting annual savings for the 
19    year ending December 31, 2020;
20        (4) 11.8% cumulative persisting annual savings for the 
21    year ending December 31, 2021;
22        (5) 13.1% cumulative persisting annual savings for the 
23    year ending December 31, 2022;
24        (6) 14.4% cumulative persisting annual savings for the 
25    year ending December 31, 2023;
26        (7) 15.7% cumulative persisting annual savings for the 
 
 
10400SB0025ham002- 449 -LRB104 07069 AAS 28576 a

1    year ending December 31, 2024;
2        (8) 17% cumulative persisting annual savings for the 
3    year ending December 31, 2025; and    
4        (9) 17.9% cumulative persisting annual savings for the 
5    year ending December 31, 2026. ;
6        (10) 18.8% cumulative persisting annual savings for 
7    the year ending December 31, 2027;
8        (11) 19.7% cumulative persisting annual savings for 
9    the year ending December 31, 2028;
10        (12) 20.6% cumulative persisting annual savings for 
11    the year ending December 31, 2029; and
12        (13) 21.5% cumulative persisting annual savings for 
13    the year ending December 31, 2030.
14    No later than December 31, 2021, the Illinois Commerce 
15Commission shall establish additional cumulative persisting 
16annual savings goals for the years 2031 through 2035. No later 
17than December 31, 2024, the Illinois Commerce Commission shall 
18establish additional cumulative persisting annual savings 
19goals for the years 2036 through 2040. The Commission shall 
20also establish additional cumulative persisting annual savings 
21goals every 5 years thereafter to ensure that utilities always 
22have goals that extend at least 11 years into the future. The 
23cumulative persisting annual savings goals beyond the year 
242030 shall increase by 0.9 percentage points per year, absent 
25a Commission decision to initiate a proceeding to consider 
26establishing goals that increase by more or less than that 
 
 
10400SB0025ham002- 450 -LRB104 07069 AAS 28576 a

1amount. Such a proceeding must be conducted in accordance with 
2the procedures described in subsection (f) of this Section. If 
3such a proceeding is initiated, the cumulative persisting 
4annual savings goals established by the Commission through 
5that proceeding shall reflect the Commission's best estimate 
6of the maximum amount of additional savings that are forecast 
7to be cost-effectively achievable unless such best estimates 
8would result in goals that represent less than 0.5 percentage 
9point annual increases in total cumulative persisting annual 
10savings. The Commission may only establish goals that 
11represent less than 0.5 percentage point annual increases in 
12cumulative persisting annual savings if it can demonstrate, 
13based on clear and convincing evidence and through independent 
14analysis, that 0.5 percentage point increases are not 
15cost-effectively achievable. The Commission shall inform its 
16decision based on an energy efficiency potential study that 
17conforms to the requirements of this Section.    
18    (b-10) For purposes of this Section, through calendar year 
192026, electric utilities subject to this Section that serve 
20less than 3,000,000 retail customers but more than 500,000 
21retail customers in the State shall be deemed to have achieved 
22a cumulative persisting annual savings of 6.6% from energy 
23efficiency measures and programs implemented during the period 
24beginning January 1, 2012 and ending December 31, 2017, which 
25is based on the deemed average weather normalized sales of 
26electric power and energy during calendar years 2014, 2015, 
 
 
10400SB0025ham002- 451 -LRB104 07069 AAS 28576 a

1and 2016 of 36,900,000 MWhs. For the purposes of this 
2subsection (b-10) and subsection (b-15), the 36,900,000 MWhs 
3of deemed electric power and energy sales shall be reduced by 
4the number of MWhs equal to the sum of the annual consumption 
5of customers that have opted out of subsections (a) through 
6(j) of this Section under paragraph (1) of subsection (l) of 
7this Section, as averaged across the calendar years 2014, 
82015, and 2016. After 2017, the deemed value of cumulative 
9persisting annual savings from energy efficiency measures and 
10programs implemented during the period beginning January 1, 
112012 and ending December 31, 2017, shall be reduced each year, 
12as follows, and the applicable value shall be applied to and 
13count toward the utility's achievement of the cumulative 
14persisting annual savings goals set forth in subsection 
15(b-15):
16        (1) 5.8% deemed cumulative persisting annual savings 
17    for the year ending December 31, 2018;
18        (2) 5.2% deemed cumulative persisting annual savings 
19    for the year ending December 31, 2019;
20        (3) 4.5% deemed cumulative persisting annual savings 
21    for the year ending December 31, 2020;
22        (4) 4.0% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2021;
24        (5) 3.5% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2022;
26        (6) 3.1% deemed cumulative persisting annual savings 
 
 
10400SB0025ham002- 452 -LRB104 07069 AAS 28576 a

1    for the year ending December 31, 2023;
2        (7) 2.8% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2024;
4        (8) 2.5% deemed cumulative persisting annual savings 
5    for the year ending December 31, 2025; and    
6        (9) 2.3% deemed cumulative persisting annual savings 
7    for the year ending December 31, 2026. ;    
8        (10) 2.1% deemed cumulative persisting annual savings 
9    for the year ending December 31, 2027;
10        (11) 1.8% deemed cumulative persisting annual savings 
11    for the year ending December 31, 2028;
12        (12) 1.7% deemed cumulative persisting annual savings 
13    for the year ending December 31, 2029;
14        (13) 1.5% deemed cumulative persisting annual savings 
15    for the year ending December 31, 2030;
16        (14) 1.3% deemed cumulative persisting annual savings 
17    for the year ending December 31, 2031;
18        (15) 1.1% deemed cumulative persisting annual savings 
19    for the year ending December 31, 2032;
20        (16) 0.9% deemed cumulative persisting annual savings 
21    for the year ending December 31, 2033;
22        (17) 0.7% deemed cumulative persisting annual savings 
23    for the year ending December 31, 2034;
24        (18) 0.5% deemed cumulative persisting annual savings 
25    for the year ending December 31, 2035;
26        (19) 0.4% deemed cumulative persisting annual savings 
 
 
10400SB0025ham002- 453 -LRB104 07069 AAS 28576 a

1    for the year ending December 31, 2036;
2        (20) 0.3% deemed cumulative persisting annual savings 
3    for the year ending December 31, 2037;
4        (21) 0.2% deemed cumulative persisting annual savings 
5    for the year ending December 31, 2038;
6        (22) 0.1% deemed cumulative persisting annual savings 
7    for the year ending December 31, 2039; and
8        (23) 0.0% deemed cumulative persisting annual savings 
9    for the year ending December 31, 2040 and all subsequent 
10    years.    
11    (b-15) Beginning in 2018 and through calendar year 2026, 
12electric utilities subject to this Section that serve less 
13than 3,000,000 retail customers but more than 500,000 retail 
14customers in the State shall achieve the following cumulative 
15persisting annual savings goals, as modified by subsection 
16(b-20) and subsection (f) of this Section and as compared to 
17the deemed baseline as reduced by the number of MWhs equal to 
18the sum of the annual consumption of customers that have opted 
19out of subsections (a) through (j) of this Section under 
20paragraph (1) of subsection (l) of this Section as averaged 
21across the calendar years 2014, 2015, and 2016, through the 
22implementation of energy efficiency measures during the 
23applicable year and in prior years, but no earlier than 
24January 1, 2012:
25        (1) 7.4% cumulative persisting annual savings for the 
26    year ending December 31, 2018;
 
 
10400SB0025ham002- 454 -LRB104 07069 AAS 28576 a

1        (2) 8.2% cumulative persisting annual savings for the 
2    year ending December 31, 2019;
3        (3) 9.0% cumulative persisting annual savings for the 
4    year ending December 31, 2020;
5        (4) 9.8% cumulative persisting annual savings for the 
6    year ending December 31, 2021;
7        (5) 10.6% cumulative persisting annual savings for the 
8    year ending December 31, 2022;
9        (6) 11.4% cumulative persisting annual savings for the 
10    year ending December 31, 2023;
11        (7) 12.2% cumulative persisting annual savings for the 
12    year ending December 31, 2024;
13        (8) 13% cumulative persisting annual savings for the 
14    year ending December 31, 2025; and    
15        (9) 13.6% cumulative persisting annual savings for the 
16    year ending December 31, 2026. ;
17        (10) 14.2% cumulative persisting annual savings for 
18    the year ending December 31, 2027;
19        (11) 14.8% cumulative persisting annual savings for 
20    the year ending December 31, 2028;
21        (12) 15.4% cumulative persisting annual savings for 
22    the year ending December 31, 2029; and
23        (13) 16% cumulative persisting annual savings for the 
24    year ending December 31, 2030.    
25    No later than December 31, 2021, the Illinois Commerce 
26Commission shall establish additional cumulative persisting 
 
 
10400SB0025ham002- 455 -LRB104 07069 AAS 28576 a

1annual savings goals for the years 2031 through 2035. No later 
2than December 31, 2024, the Illinois Commerce Commission shall 
3establish additional cumulative persisting annual savings 
4goals for the years 2036 through 2040. The Commission shall 
5also establish additional cumulative persisting annual savings 
6goals every 5 years thereafter to ensure that utilities always 
7have goals that extend at least 11 years into the future. The 
8cumulative persisting annual savings goals beyond the year 
92030 shall increase by 0.6 percentage points per year, absent 
10a Commission decision to initiate a proceeding to consider 
11establishing goals that increase by more or less than that 
12amount. Such a proceeding must be conducted in accordance with 
13the procedures described in subsection (f) of this Section. If 
14such a proceeding is initiated, the cumulative persisting 
15annual savings goals established by the Commission through 
16that proceeding shall reflect the Commission's best estimate 
17of the maximum amount of additional savings that are forecast 
18to be cost-effectively achievable unless such best estimates 
19would result in goals that represent less than 0.4 percentage 
20point annual increases in total cumulative persisting annual 
21savings. The Commission may only establish goals that 
22represent less than 0.4 percentage point annual increases in 
23cumulative persisting annual savings if it can demonstrate, 
24based on clear and convincing evidence and through independent 
25analysis, that 0.4 percentage point increases are not 
26cost-effectively achievable. The Commission shall inform its 
 
 
10400SB0025ham002- 456 -LRB104 07069 AAS 28576 a

1decision based on an energy efficiency potential study that 
2conforms to the requirements of this Section.    
3    (b-16) In 2027 and each year thereafter, each electric 
4utility subject to this Section shall achieve the following 
5savings goals:
6        (1) A utility that serves more than 3,000,000 retail 
7    customers in the State must achieve incremental annual 
8    energy savings for customers in an amount that is equal to 
9    2% of the utility's average annual electricity sales from 
10    2021 through 2023 to customers. A utility that serves less 
11    than 3,000,000 retail customers but more than 500,000 
12    retail customers in the State must achieve incremental 
13    annual energy savings for customers in an amount that is 
14    equal to 1.4% in 2027, 1.7% in 2028, and 2% in 2029 and 
15    every year thereafter of the utility's average annual 
16    electricity sales from 2021 through 2023 to customers. The 
17    incremental annual energy savings requirements set forth 
18    in this paragraph (1) may be reduced by 0.025 percentage 
19    points for every percentage point increase, above the 25% 
20    minimum to be targeted at low-income households as 
21    specified in paragraph (c) of this Section, in the portion 
22    of total efficiency program spending that is on low-income 
23    or moderate-income efficiency programs. The incremental 
24    annual savings requirement shall not be reduced to a level 
25    less than 25% less than the energy savings requirement 
26    applicable to the calendar year, even if the sum of 
 
 
10400SB0025ham002- 457 -LRB104 07069 AAS 28576 a

1    low-income spending and moderate-income spending is 
2    greater than 35% of total spending.
3        (2) A utility that serves less than 3,000,000 retail 
4    customers but more than 500,000 retail customers in the 
5    State must achieve an incremental annual coincident peak 
6    demand savings goal from energy efficiency measures 
7    installed as a result of the utility's programs by 
8    customers in an amount that is equal to the energy savings 
9    goal from paragraph (1) of this Section divided by the 
10    actual average ratio of kilowatt-hour savings to 
11    coincident peak demand reduction achieved by the utility 
12    through its energy efficiency programs in 2023. If the 
13    season in which coincident peak demands are experienced, 
14    the hours of the day that peak demands are experienced, 
15    and the methods by which peak demand impacts from 
16    efficiency measures are estimated are different in the 
17    future than when 2023 peak demand impacts were originally 
18    estimated, the 2023 peak demand impacts shall be 
19    recomputed using such updated peak definitions and 
20    estimation methods for the purpose of establishing future 
21    coincident peak demand savings goals. To the extent that a 
22    utility counts either improvements to the efficiency of 
23    the use of gas and other fuels or the electrification of 
24    gas and other fuels toward its energy savings goal, as 
25    permitted under paragraphs (b-25) and (b-27) of this 
26    Section, it must estimate the actual impacts on coincident 
 
 
10400SB0025ham002- 458 -LRB104 07069 AAS 28576 a

1    peak demand from such measures and count them, whether 
2    positive or negative, toward its coincident peak demand 
3    savings goal. Only coincident peak demand savings from 
4    efficiency measures shall count toward this goal. To the 
5    extent that some efficiency measures enable demand 
6    response, only the peak demand savings from the energy 
7    efficiency upgrade shall count toward the goal. Nothing in 
8    this Section shall limit the ability of peak demand 
9    savings from such enabled demand-response initiatives to 
10    count for other, non-energy efficiency performance 
11    standard performance metrics established for the utility.
12        (3) Each utility's incremental annual energy savings, 
13    and coincident peak demand savings if a utility serves 
14    less than 3,000,000 retail customers but more than 500,000 
15    retail customers in the State, must be achieved with an 
16    average savings life of at least 12 years. In no event can 
17    more than one-fifth of the incremental annual savings or 
18    the coincident peak demand savings counted toward a 
19    utility's annual savings goal in any given year be derived 
20    from efficiency measures with average savings lives of 
21    less than 5 years. Average savings lives may be shorter 
22    than the average operational lives of measures installed 
23    if the measures do not produce savings in every year in 
24    which the measures operate or if the savings that measures 
25    produce decline during the measures' operational lives.
26            For the purposes of this Section, "incremental annual 
 
 
10400SB0025ham002- 459 -LRB104 07069 AAS 28576 a

1    energy savings" means the total electric energy savings 
2    from all measures installed in a calendar year that will 
3    be realized within 12 months of each measure's 
4    installation; "moderate-income" means income between 80% 
5    of area median income and 300% of the federal poverty 
6    limit; "incremental annual coincident peak demand savings" 
7    means the total coincident peak reduction from all energy 
8    efficiency measures installed in a calendar year that will 
9    be realized within 12 months of each measure's 
10    installation; "average savings life" means the lifetime 
11    savings that would be realized as a result of a utility's 
12    efficiency programs divided by the incremental annual 
13    savings such programs produce.    
14    (b-20) Each electric utility subject to this Section may 
15include cost-effective voltage optimization measures in its 
16plans submitted under subsections (f) and (g) of this Section, 
17and the costs incurred by a utility to implement the measures 
18under a Commission-approved plan shall be recovered under the 
19provisions of Article IX or Section 16-108.5 of this Act. For 
20purposes of this Section, the measure life of voltage 
21optimization measures shall be 15 years. The measure life 
22period is independent of the depreciation rate of the voltage 
23optimization assets deployed. Utilities may claim savings from 
24voltage optimization on circuits for more than 15 years if 
25they can demonstrate that they have made additional 
26investments necessary to enable voltage optimization savings 
 
 
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1to continue beyond 15 years. Such demonstrations must be 
2subject to the review of independent evaluation. 
3    Within 270 days after June 1, 2017 (the effective date of 
4Public Act 99-906), an electric utility that serves less than 
53,000,000 retail customers but more than 500,000 retail 
6customers in the State shall file a plan with the Commission 
7that identifies the cost-effective voltage optimization 
8investment the electric utility plans to undertake through 
9December 31, 2024. The Commission, after notice and hearing, 
10shall approve or approve with modification the plan within 120 
11days after the plan's filing and, in the order approving or 
12approving with modification the plan, the Commission shall 
13adjust the applicable cumulative persisting annual savings 
14goals set forth in subsection (b-15) to reflect any amount of 
15cost-effective energy savings approved by the Commission that 
16is greater than or less than the following cumulative 
17persisting annual savings values attributable to voltage 
18optimization for the applicable year:
19        (1) 0.0% of cumulative persisting annual savings for 
20    the year ending December 31, 2018;
21        (2) 0.17% of cumulative persisting annual savings for 
22    the year ending December 31, 2019;
23        (3) 0.17% of cumulative persisting annual savings for 
24    the year ending December 31, 2020;
25        (4) 0.33% of cumulative persisting annual savings for 
26    the year ending December 31, 2021;
 
 
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1        (5) 0.5% of cumulative persisting annual savings for 
2    the year ending December 31, 2022;
3        (6) 0.67% of cumulative persisting annual savings for 
4    the year ending December 31, 2023;
5        (7) 0.83% of cumulative persisting annual savings for 
6    the year ending December 31, 2024; and
7        (8) 1.0% of cumulative persisting annual savings for 
8    the year ending December 31, 2025 and all subsequent 
9    years. 
10    (b-25) In the event an electric utility jointly offers an 
11energy efficiency measure or program with a gas utility under 
12plans approved under this Section and Section 8-104 of this 
13Act, the electric utility may continue offering the program, 
14including the gas energy efficiency measures, in the event the 
15gas utility discontinues funding the program. In that event, 
16the energy savings value associated with such other fuels 
17shall be converted to electric energy savings on an equivalent 
18Btu basis for the premises. However, the electric utility 
19shall prioritize programs for low-income residential customers 
20to the extent practicable. An electric utility may recover the 
21costs of offering the gas energy efficiency measures under 
22this subsection (b-25).
23    For those energy efficiency measures or programs that save 
24both electricity and other fuels but are not jointly offered 
25with a gas utility under plans approved under this Section and 
26Section 8-104 or not offered with an affiliated gas utility 
 
 
10400SB0025ham002- 462 -LRB104 07069 AAS 28576 a

1under paragraph (6) of subsection (f) of Section 8-104 of this 
2Act, the electric utility may count savings of fuels other 
3than electricity toward the achievement of its annual savings 
4goal, and the energy savings value associated with such other 
5fuels shall be converted to electric energy savings on an 
6equivalent Btu basis at the premises. 
7    For an electric utility that serves more than 3,000,000 
8retail customers in the State, on and after January 1, 2027, 
9the electric utility may only count savings of other fuels 
10under this subsection (b-25) toward the achievement of its 
11annual electric energy savings goal when such other fuel 
12savings are from weatherization measures that reduce heat loss 
13through the building envelope or heating distribution system, 
14including, but not limited to, air sealing and building shell 
15measures. This limitation on counting other fuel savings from 
16efficiency measures toward a utility's energy savings goal 
17shall not affect the utility's ability to claim savings from 
18electrification measures installed pursuant to the 
19requirements in subsection (b-27).    
20    In no event shall more than 10% of each year's applicable 
21annual total savings requirement, as defined in paragraph 
22(7.5) of subsection (g) of this Section be met through savings 
23of fuels other than electricity. For an electric utility that 
24serves more than 3,000,000 retail customers in the State, in 
25no event shall more than 30% of each year's incremental annual 
26energy savings requirement, as defined in subsection (b-16) of 
 
 
10400SB0025ham002- 463 -LRB104 07069 AAS 28576 a

1this Section, be met through savings of fuels other than 
2electricity. For an electric utility that serves less than 
33,000,000 retail customers but more than 500,000 retail 
4customers in the State, in no event shall more than 20% of each 
5year's incremental annual energy savings requirement, as 
6defined in subsection (b-16) of this Section, be met through 
7savings of fuels other than electricity.    
8    (b-27) Beginning in 2022, an electric utility may offer 
9and promote measures that electrify space heating, water 
10heating, cooling, drying, cooking, industrial processes, and 
11other building and industrial end uses that would otherwise be 
12served by combustion of fossil fuel at the premises, provided 
13that the electrification measures reduce total energy 
14consumption at the premises. The electric utility may count 
15the reduction in energy consumption at the premises toward 
16achievement of its annual savings goals. The reduction in 
17energy consumption at the premises shall be calculated as the 
18difference between: (A) the reduction in Btu consumption of 
19fossil fuels as a result of electrification, converted to 
20kilowatt-hour equivalents by dividing by 3,412 Btus per 
21kilowatt hour; and (B) the increase in kilowatt hours of 
22electricity consumption resulting from the displacement of 
23fossil fuel consumption as a result of electrification. An 
24electric utility may recover the costs of offering and 
25promoting electrification measures under this subsection 
26(b-27).
 
 
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1    At least 33% of all costs of offering and promoting 
2electrification measures under this subsection (b-27) must be 
3for supporting installation of electrification measures 
4through programs exclusively targeted to low-income 
5households. The percentage requirement may be reduced if the 
6utility can demonstrate that it is not possible to achieve the 
7level of low-income electrification spending, while supporting 
8programs for non-low-income residential and business 
9electrification, because of limitations regarding the number 
10of low-income households in its service territory that would 
11be able to meet program eligibility requirements set forth in 
12the multi-year energy efficiency plan. If the 33% low-income 
13electrification spending requirement is reduced, the utility 
14must prioritize support of low-income electrification in 
15housing that meets program eligibility requirements over 
16electrification spending on non-low-income residential or 
17business customers.
18    The ratio of spending on electrification measures targeted 
19to low-income, multifamily buildings to spending on 
20electrification measures targeted to low-income, single-family 
21buildings shall be designed to achieve levels of 
22electrification savings from each building type that are 
23approximately proportional to the magnitude of cost-effective 
24electrification savings potential in each building type.    
25    In no event shall electrification savings counted toward 
26each year's applicable annual total savings requirement, as 
 
 
10400SB0025ham002- 465 -LRB104 07069 AAS 28576 a

1defined in paragraph (7.5) of subsection (g) of this Section, 
2or counted toward each year's incremental annual savings, as 
3defined in paragraph (b-16) of this Section, be greater than:
4        (1) 5% per year for each year from 2022 through 2025;
5        (2) 20% 10% per year for each year from 2026 and all 
6    subsequent years through 2029; and
7        (3) (blank). 15% per year for 2030 and all subsequent 
8    years.
9In addition, a minimum of 25% of all electrification savings 
10counted toward a utility's applicable annual total savings 
11requirement must be from electrification of end uses in 
12low-income housing. The limitations on electrification savings 
13that may be counted toward a utility's annual savings goals 
14are separate from and in addition to the subsection (b-25) 
15limitations governing the counting of the other fuel savings 
16resulting from efficiency measures and programs.
17    As part of the annual informational filing to the 
18Commission that is required under paragraph (9) of subsection 
19(g) of this Section, each utility shall identify the specific 
20electrification measures offered under this subsection (b-27); 
21the quantity of each electrification measure that was 
22installed by its customers; the average total cost, average 
23utility cost, average reduction in fossil fuel consumption, 
24and average increase in electricity consumption associated 
25with each electrification measure; the portion of 
26installations of each electrification measure that were in 
 
 
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1low-income single-family housing, low-income multifamily 
2housing, non-low-income single-family housing, non-low-income 
3multifamily housing, commercial buildings, and industrial 
4facilities; and the quantity of savings associated with each 
5measure category in each customer category that are being 
6counted toward the utility's applicable annual total savings 
7requirement or counted toward each year's incremental annual 
8savings, as defined in paragraph (b-16) of this Section. Prior 
9to installing or promoting an electrification measures    
10measure, the utility shall provide customers a customer with 
11estimates an estimate of the impact of the new measures    
12measure on the customer's average monthly electric bill and 
13total annual energy expenses. 
14    (c) Electric utilities shall be responsible for overseeing 
15the design, development, and filing of energy efficiency plans 
16with the Commission and may, as part of that implementation, 
17outsource various aspects of program development and 
18implementation. A minimum of 10%, for electric utilities that 
19serve more than 3,000,000 retail customers in the State, and a 
20minimum of 7%, for electric utilities that serve less than 
213,000,000 retail customers but more than 500,000 retail 
22customers in the State, of the utility's entire portfolio 
23funding level for a given year shall be used to procure 
24cost-effective energy efficiency measures from units of local 
25government, municipal corporations, school districts, public 
26housing, public institutions of higher education, and 
 
 
10400SB0025ham002- 467 -LRB104 07069 AAS 28576 a

1community college districts, provided that a minimum 
2percentage of available funds shall be used to procure energy 
3efficiency from public housing, which percentage shall be 
4equal to public housing's share of public building energy 
5consumption.
6    The utilities shall also implement energy efficiency 
7measures targeted at low-income households, which, for 
8purposes of this Section, shall be defined as households at or 
9below 80% of area median income, and expenditures to implement 
10the measures shall be no less than 25% of total energy 
11efficiency program spending approved by the Commission 
12pursuant to review of plans filed under subsection (f) of this 
13Section $40,000,000 per year for electric utilities that serve 
14more than 3,000,000 retail customers in the State and no less 
15than $13,000,000 per year for electric utilities that serve 
16less than 3,000,000 retail customers but more than 500,000 
17retail customers in the State. The ratio of spending on 
18efficiency programs targeted at low-income multifamily 
19buildings to spending on efficiency programs targeted at 
20low-income single-family buildings shall be designed to 
21achieve levels of savings from each building type that are 
22approximately proportional to the magnitude of cost-effective 
23lifetime savings potential in each building type. Investment 
24in low-income whole-building weatherization programs shall 
25constitute a minimum of 80% of a utility's total budget 
26specifically dedicated to serving low-income customers.
 
 
10400SB0025ham002- 468 -LRB104 07069 AAS 28576 a

1    The utilities shall work to bundle low-income energy 
2efficiency offerings with other programs that serve low-income 
3households to maximize the benefits going to these households. 
4The utilities shall market and implement low-income energy 
5efficiency programs in coordination with low-income assistance 
6programs, the Illinois Solar for All Program, and 
7weatherization whenever practicable. The program implementer 
8shall walk the customer through the enrollment process for any 
9programs for which the customer is eligible. The utilities 
10shall also pilot targeting customers with high arrearages, 
11high energy intensity (ratio of energy usage divided by home 
12or unit square footage), or energy assistance programs with 
13energy efficiency offerings, and then track reduction in 
14arrearages as a result of the targeting. This targeting and 
15bundling of low-income energy programs shall be offered to 
16both low-income single-family and multifamily customers 
17(owners and residents). 
18    The utilities shall invest in health and safety measures 
19appropriate and necessary for comprehensively weatherizing a 
20home or multifamily building, and shall implement a health and 
21safety fund of at least 15% of the total income-qualified 
22weatherization budget that shall be used for the purpose of 
23making grants for technical assistance, construction, 
24reconstruction, improvement, or repair of buildings to 
25facilitate their participation in the energy efficiency 
26programs targeted at low-income single-family and multifamily 
 
 
10400SB0025ham002- 469 -LRB104 07069 AAS 28576 a

1households. These funds may also be used for the purpose of 
2making grants for technical assistance, construction, 
3reconstruction, improvement, or repair of the following 
4buildings to facilitate their participation in the energy 
5efficiency programs created by this Section: (1) buildings 
6that are owned or operated by registered 501(c)(3) public 
7charities; and (2) day care centers, day care homes, or group 
8day care homes, as defined under 89 Ill. Adm. Code Part 406, 
9407, or 408, respectively. 
10    Each electric utility shall assess opportunities to 
11implement cost-effective energy efficiency measures and 
12programs through a public housing authority or authorities 
13located in its service territory. If such opportunities are 
14identified, the utility shall propose such measures and 
15programs to address the opportunities. Expenditures to address 
16such opportunities shall be credited toward the minimum 
17procurement and expenditure requirements set forth in this 
18subsection (c).
19    Implementation of energy efficiency measures and programs 
20targeted at low-income households should be contracted, when 
21it is practicable, to independent third parties that have 
22demonstrated capabilities to serve such households, with a 
23preference for not-for-profit entities and government agencies 
24that have existing relationships with or experience serving 
25low-income communities in the State.
26    Each electric utility shall develop and implement 
 
 
10400SB0025ham002- 470 -LRB104 07069 AAS 28576 a

1reporting procedures that address and assist in determining 
2the amount of energy savings that can be applied to the 
3low-income procurement and expenditure requirements set forth 
4in this subsection (c). Each electric utility shall also track 
5the types and quantities or volumes of insulation and air 
6sealing materials, and their associated energy saving 
7benefits, installed in energy efficiency programs targeted at 
8low-income single-family and multifamily households. 
9    The electric utilities shall participate in a low-income 
10energy efficiency accountability committee ("the committee"), 
11which will directly inform the design, implementation, and 
12evaluation of the low-income and public-housing energy 
13efficiency programs. The committee shall be comprised of the 
14electric utilities subject to the requirements of this 
15Section, the gas utilities subject to the requirements of 
16Section 8-104 of this Act, the utilities' low-income energy 
17efficiency implementation contractors, nonprofit 
18organizations, community action agencies, advocacy groups, 
19State and local governmental agencies, public-housing 
20organizations, and representatives of community-based 
21organizations, especially those living in or working with 
22environmental justice communities and BIPOC communities. The 
23committee shall be composed of 2 geographically differentiated 
24subcommittees: one for stakeholders in northern Illinois and 
25one for stakeholders in central and southern Illinois. The 
26subcommittees shall meet together at least twice per year.
 
 
10400SB0025ham002- 471 -LRB104 07069 AAS 28576 a

1    There shall be one statewide leadership committee led by 
2and composed of community-based organizations that are 
3representative of BIPOC and environmental justice communities 
4and that includes equitable representation from BIPOC 
5communities. The leadership committee shall be composed of an 
6equal number of representatives from the 2 subcommittees. The 
7subcommittees shall address specific programs and issues, with 
8the leadership committee convening targeted workgroups as 
9needed. The leadership committee may elect to work with an 
10independent facilitator to solicit and organize feedback, 
11recommendations and meeting participation from a wide variety 
12of community-based stakeholders. If a facilitator is used, 
13they shall be fair and responsive to the needs of all 
14stakeholders involved in the committee. For a utility that 
15serves more than 3,000,000 retail customers in the State, if a 
16facilitator is used, they shall be retained by Commission 
17staff.    
18     All committee meetings must be accessible, with rotating 
19locations if meetings are held in-person, virtual 
20participation options, and materials and agendas circulated in 
21advance.
22    There shall also be opportunities for direct input by 
23committee members outside of committee meetings, such as via 
24individual meetings, surveys, emails and calls, to ensure 
25robust participation by stakeholders with limited capacity and 
26ability to attend committee meetings. Committee meetings shall 
 
 
10400SB0025ham002- 472 -LRB104 07069 AAS 28576 a

1emphasize opportunities to bundle and coordinate delivery of 
2low-income energy efficiency with other programs that serve 
3low-income communities, such as the Illinois Solar for All 
4Program and bill payment assistance programs. Meetings shall 
5include educational opportunities for stakeholders to learn 
6more about these additional offerings, and the committee shall 
7assist in figuring out the best methods for coordinated 
8delivery and implementation of offerings when serving 
9low-income communities. The committee shall directly and 
10equitably influence and inform utility low-income and 
11public-housing energy efficiency programs and priorities. 
12Participating utilities shall implement recommendations from 
13the committee whenever possible.
14    Participating utilities shall track and report how input 
15from the committee has led to new approaches and changes in 
16their energy efficiency portfolios. This reporting shall occur 
17at committee meetings and in quarterly energy efficiency 
18reports to the Stakeholder Advisory Group and Illinois 
19Commerce Commission, and other relevant reporting mechanisms. 
20Participating utilities shall also report on relevant equity 
21data and metrics requested by the committee, such as energy 
22burden data, geographic, racial, and other relevant 
23demographic data on where programs are being delivered and 
24what populations programs are serving.
25    The Illinois Commerce Commission shall oversee and have 
26relevant staff participate in the committee. The committee 
 
 
10400SB0025ham002- 473 -LRB104 07069 AAS 28576 a

1shall have a budget of 0.25% of each utility's entire 
2efficiency portfolio funding for a given year. The budget 
3shall be overseen by the Commission. The budget shall be used 
4to provide grants for community-based organizations serving on 
5the leadership committee, stipends for community-based 
6organizations participating in the committee, grants for 
7community-based organizations to do energy efficiency outreach 
8and education, and relevant meeting needs as determined by the 
9leadership committee. The education and outreach shall 
10include, but is not limited to, basic energy efficiency 
11education, information about low-income energy efficiency 
12programs, and information on the committee's purpose, 
13structure, and activities.
14    (d) Notwithstanding any other provision of law to the 
15contrary, a utility providing approved energy efficiency 
16measures and, if applicable, demand-response measures in the 
17State shall be permitted to recover all reasonable and 
18prudently incurred costs of those measures from all retail 
19customers, except as provided in subsection (l) of this 
20Section, as follows, provided that nothing in this subsection 
21(d) permits the double recovery of such costs from customers: 
22        (1) The utility may recover its costs through an 
23    automatic adjustment clause tariff filed with and approved 
24    by the Commission. The tariff shall be established outside 
25    the context of a general rate case. Each year the 
26    Commission shall initiate a review to reconcile any 
 
 
10400SB0025ham002- 474 -LRB104 07069 AAS 28576 a

1    amounts collected with the actual costs and to determine 
2    the required adjustment to the annual tariff factor to 
3    match annual expenditures. To enable the financing of the 
4    incremental capital expenditures, including regulatory 
5    assets, for electric utilities that serve less than 
6    3,000,000 retail customers but more than 500,000 retail 
7    customers in the State, the utility's actual year-end 
8    capital structure that includes a common equity ratio, 
9    excluding goodwill, of up to and including 50% of the 
10    total capital structure shall be deemed reasonable and 
11    used to set rates.
12        (2) A utility may recover its costs through an energy 
13    efficiency formula rate approved by the Commission under a 
14    filing under subsections (f) and (g) of this Section, 
15    which shall specify the cost components that form the 
16    basis of the rate charged to customers with sufficient 
17    specificity to operate in a standardized manner and be 
18    updated annually with transparent information that 
19    reflects the utility's actual costs to be recovered during 
20    the applicable rate year, which is the period beginning 
21    with the first billing day of January and extending 
22    through the last billing day of the following December. 
23    The energy efficiency formula rate shall be implemented 
24    through a tariff filed with the Commission under 
25    subsections (f) and (g) of this Section that is consistent 
26    with the provisions of this paragraph (2) and that shall 
 
 
10400SB0025ham002- 475 -LRB104 07069 AAS 28576 a

1    be applicable to all delivery services customers. The 
2    Commission shall conduct an investigation of the tariff in 
3    a manner consistent with the provisions of this paragraph 
4    (2), subsections (f) and (g) of this Section, and the 
5    provisions of Article IX of this Act to the extent they do 
6    not conflict with this paragraph (2). The energy 
7    efficiency formula rate approved by the Commission shall 
8    remain in effect at the discretion of the utility and 
9    shall do the following:
10            (A) Provide for the recovery of the utility's 
11        actual costs incurred under this Section that are 
12        prudently incurred and reasonable in amount consistent 
13        with Commission practice and law. The sole fact that a 
14        cost differs from that incurred in a prior calendar 
15        year or that an investment is different from that made 
16        in a prior calendar year shall not imply the 
17        imprudence or unreasonableness of that cost or 
18        investment.
19            (B) Reflect the utility's actual year-end capital 
20        structure for the applicable calendar year, excluding 
21        goodwill, subject to a determination of prudence and 
22        reasonableness consistent with Commission practice and 
23        law. To enable the financing of the incremental 
24        capital expenditures, including regulatory assets, for 
25        electric utilities that serve less than 3,000,000 
26        retail customers but more than 500,000 retail 
 
 
10400SB0025ham002- 476 -LRB104 07069 AAS 28576 a

1        customers in the State, a participating electric 
2        utility's actual year-end capital structure that 
3        includes a common equity ratio, excluding goodwill, of 
4        up to and including 50% of the total capital structure 
5        shall be deemed reasonable and used to set rates.
6            (C) Include a cost of equity that shall be equal to 
7        the baseline cost of equity approved by the Commission 
8        for the utility's electric distribution rates 
9        effective during the applicable year, whether those 
10        rates are set pursuant to Section 9-201, subparagraph 
11        (B) of paragraph (3) of subsection (d) of Section 
12        16-108.18, or any successor electric distribution 
13        ratemaking paradigm. , which shall be calculated as the 
14        sum of the following:
15                (i) the average for the applicable calendar 
16            year of the monthly average yields of 30-year U.S. 
17            Treasury bonds published by the Board of Governors 
18            of the Federal Reserve System in its weekly H.15 
19            Statistical Release or successor publication; and
20                (ii) 580 basis points.
21            At such time as the Board of Governors of the 
22        Federal Reserve System ceases to include the monthly 
23        average yields of 30-year U.S. Treasury bonds in its 
24        weekly H.15 Statistical Release or successor 
25        publication, the monthly average yields of the U.S. 
26        Treasury bonds then having the longest duration 
 
 
10400SB0025ham002- 477 -LRB104 07069 AAS 28576 a

1        published by the Board of Governors in its weekly H.15 
2        Statistical Release or successor publication shall 
3        instead be used for purposes of this paragraph (2).
4            (D) Permit and set forth protocols, subject to a 
5        determination of prudence and reasonableness 
6        consistent with Commission practice and law, for the 
7        following:
8                (i) recovery of incentive compensation expense 
9            that is based on the achievement of operational 
10            metrics, including metrics related to budget 
11            controls, outage duration and frequency, safety, 
12            customer service, efficiency and productivity, and 
13            environmental compliance; however, this protocol 
14            shall not apply if such expense related to costs 
15            incurred under this Section is recovered under 
16            Article IX or Section 16-108.5 of this Act; 
17            incentive compensation expense that is based on 
18            net income or an affiliate's earnings per share 
19            shall not be recoverable under the energy 
20            efficiency formula rate;
21                (ii) recovery of pension and other 
22            post-employment benefits expense, provided that 
23            such costs are supported by an actuarial study; 
24            however, this protocol shall not apply if such 
25            expense related to costs incurred under this 
26            Section is recovered under Article IX or Section 
 
 
10400SB0025ham002- 478 -LRB104 07069 AAS 28576 a

1            16-108.5 of this Act;
2                (iii) recovery of existing regulatory assets 
3            over the periods previously authorized by the 
4            Commission;
5                (iv) as described in subsection (e), 
6            amortization of costs incurred under this Section; 
7            and
8                (v) projected, weather normalized billing 
9            determinants for the applicable rate year.
10            (E) Provide for an annual reconciliation, as 
11        described in paragraph (3) of this subsection (d), 
12        less any deferred taxes related to the reconciliation, 
13        with interest at an annual rate of return equal to the 
14        utility's weighted average cost of capital, including 
15        a revenue conversion factor calculated to recover or 
16        refund all additional income taxes that may be payable 
17        or receivable as a result of that return, of the energy 
18        efficiency revenue requirement reflected in rates for 
19        each calendar year, beginning with the calendar year 
20        in which the utility files its energy efficiency 
21        formula rate tariff under this paragraph (2), with 
22        what the revenue requirement would have been had the 
23        actual cost information for the applicable calendar 
24        year been available at the filing date.
25        The utility shall file, together with its tariff, the 
26    projected costs to be incurred by the utility during the 
 
 
10400SB0025ham002- 479 -LRB104 07069 AAS 28576 a

1    rate year under the utility's multi-year plan approved 
2    under subsections (f) and (g) of this Section, including, 
3    but not limited to, the projected capital investment costs 
4    and projected regulatory asset balances with 
5    correspondingly updated depreciation and amortization 
6    reserves and expense, that shall populate the energy 
7    efficiency formula rate and set the initial rates under 
8    the formula.
9        The Commission shall review the proposed tariff in 
10    conjunction with its review of a proposed multi-year plan, 
11    as specified in paragraph (5) of subsection (g) of this 
12    Section. The review shall be based on the same evidentiary 
13    standards, including, but not limited to, those concerning 
14    the prudence and reasonableness of the costs incurred by 
15    the utility, the Commission applies in a hearing to review 
16    a filing for a general increase in rates under Article IX 
17    of this Act. The initial rates shall take effect beginning 
18    with the January monthly billing period following the 
19    Commission's approval.
20        The tariff's rate design and cost allocation across 
21    customer classes shall be consistent with the utility's 
22    automatic adjustment clause tariff in effect on June 1, 
23    2017 (the effective date of Public Act 99-906); however, 
24    the Commission may revise the tariff's rate design and 
25    cost allocation in subsequent proceedings under paragraph 
26    (3) of this subsection (d).
 
 
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1        If the energy efficiency formula rate is terminated, 
2    the then current rates shall remain in effect until such 
3    time as the energy efficiency costs are incorporated into 
4    new rates that are set under this subsection (d) or 
5    Article IX of this Act, subject to retroactive rate 
6    adjustment, with interest, to reconcile rates charged with 
7    actual costs.
8        (3) The provisions of this paragraph (3) shall only 
9    apply to an electric utility that has elected to file an 
10    energy efficiency formula rate under paragraph (2) of this 
11    subsection (d). Subsequent to the Commission's issuance of 
12    an order approving the utility's energy efficiency formula 
13    rate structure and protocols, and initial rates under 
14    paragraph (2) of this subsection (d), the utility shall 
15    file, on or before June 1 of each year, with the Chief 
16    Clerk of the Commission its updated cost inputs to the 
17    energy efficiency formula rate for the applicable rate 
18    year and the corresponding new charges, as well as the 
19    information described in paragraph (9) of subsection (g) 
20    of this Section. Each such filing shall conform to the 
21    following requirements and include the following 
22    information:
23            (A) The inputs to the energy efficiency formula 
24        rate for the applicable rate year shall be based on the 
25        projected costs to be incurred by the utility during 
26        the rate year under the utility's multi-year plan 
 
 
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1        approved under subsections (f) and (g) of this 
2        Section, including, but not limited to, projected 
3        capital investment costs and projected regulatory 
4        asset balances with correspondingly updated 
5        depreciation and amortization reserves and expense. 
6        The filing shall also include a reconciliation of the 
7        energy efficiency revenue requirement that was in 
8        effect for the prior rate year (as set by the cost 
9        inputs for the prior rate year) with the actual 
10        revenue requirement for the prior rate year 
11        (determined using a year-end rate base) that uses 
12        amounts reflected in the applicable FERC Form 1 that 
13        reports the actual costs for the prior rate year. Any 
14        over-collection or under-collection indicated by such 
15        reconciliation shall be reflected as a credit against, 
16        or recovered as an additional charge to, respectively, 
17        with interest calculated at a rate equal to the 
18        utility's weighted average cost of capital approved by 
19        the Commission for the prior rate year, the charges 
20        for the applicable rate year. Such over-collection or 
21        under-collection shall be adjusted to remove any 
22        deferred taxes related to the reconciliation, for 
23        purposes of calculating interest at an annual rate of 
24        return equal to the utility's weighted average cost of 
25        capital approved by the Commission for the prior rate 
26        year, including a revenue conversion factor calculated 
 
 
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1        to recover or refund all additional income taxes that 
2        may be payable or receivable as a result of that 
3        return. Each reconciliation shall be certified by the 
4        participating utility in the same manner that FERC 
5        Form 1 is certified. The filing shall also include the 
6        charge or credit, if any, resulting from the 
7        calculation required by subparagraph (E) of paragraph 
8        (2) of this subsection (d).
9            Notwithstanding any other provision of law to the 
10        contrary, the intent of the reconciliation is to 
11        ultimately reconcile both the revenue requirement 
12        reflected in rates for each calendar year, beginning 
13        with the calendar year in which the utility files its 
14        energy efficiency formula rate tariff under paragraph 
15        (2) of this subsection (d), with what the revenue 
16        requirement determined using a year-end rate base for 
17        the applicable calendar year would have been had the 
18        actual cost information for the applicable calendar 
19        year been available at the filing date.
20            For purposes of this Section, "FERC Form 1" means 
21        the Annual Report of Major Electric Utilities, 
22        Licensees and Others that electric utilities are 
23        required to file with the Federal Energy Regulatory 
24        Commission under the Federal Power Act, Sections 3, 
25        4(a), 304 and 209, modified as necessary to be 
26        consistent with 83 Ill. Adm. Code Part 415 as of May 1, 
 
 
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1        2011. Nothing in this Section is intended to allow 
2        costs that are not otherwise recoverable to be 
3        recoverable by virtue of inclusion in FERC Form 1.
4            (B) The new charges shall take effect beginning on 
5        the first billing day of the following January billing 
6        period and remain in effect through the last billing 
7        day of the next December billing period regardless of 
8        whether the Commission enters upon a hearing under 
9        this paragraph (3).
10            (C) The filing shall include relevant and 
11        necessary data and documentation for the applicable 
12        rate year. Normalization adjustments shall not be 
13        required.
14        Within 45 days after the utility files its annual 
15    update of cost inputs to the energy efficiency formula 
16    rate, the Commission shall with reasonable notice, 
17    initiate a proceeding concerning whether the projected 
18    costs to be incurred by the utility and recovered during 
19    the applicable rate year, and that are reflected in the 
20    inputs to the energy efficiency formula rate, are 
21    consistent with the utility's approved multi-year plan 
22    under subsections (f) and (g) of this Section and whether 
23    the costs incurred by the utility during the prior rate 
24    year were prudent and reasonable. The Commission shall 
25    also have the authority to investigate the information and 
26    data described in paragraph (9) of subsection (g) of this 
 
 
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1    Section, including the proposed adjustment to the 
2    utility's return on equity component of its weighted 
3    average cost of capital. During the course of the 
4    proceeding, each objection shall be stated with 
5    particularity and evidence provided in support thereof, 
6    after which the utility shall have the opportunity to 
7    rebut the evidence. Discovery shall be allowed consistent 
8    with the Commission's Rules of Practice, which Rules of 
9    Practice shall be enforced by the Commission or the 
10    assigned administrative law judge. The Commission shall 
11    apply the same evidentiary standards, including, but not 
12    limited to, those concerning the prudence and 
13    reasonableness of the costs incurred by the utility, 
14    during the proceeding as it would apply in a proceeding to 
15    review a filing for a general increase in rates under 
16    Article IX of this Act. The Commission shall not, however, 
17    have the authority in a proceeding under this paragraph 
18    (3) to consider or order any changes to the structure or 
19    protocols of the energy efficiency formula rate approved 
20    under paragraph (2) of this subsection (d). In a 
21    proceeding under this paragraph (3), the Commission shall 
22    enter its order no later than the earlier of 195 days after 
23    the utility's filing of its annual update of cost inputs 
24    to the energy efficiency formula rate or December 15. The 
25    utility's proposed return on equity calculation, as 
26    described in paragraphs (7) through (9) of subsection (g) 
 
 
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1    of this Section, shall be deemed the final, approved 
2    calculation on December 15 of the year in which it is filed 
3    unless the Commission enters an order on or before 
4    December 15, after notice and hearing, that modifies such 
5    calculation consistent with this Section. The Commission's 
6    determinations of the prudence and reasonableness of the 
7    costs incurred, and determination of such return on equity 
8    calculation, for the applicable calendar year shall be 
9    final upon entry of the Commission's order and shall not 
10    be subject to reopening, reexamination, or collateral 
11    attack in any other Commission proceeding, case, docket, 
12    order, rule, or regulation; however, nothing in this 
13    paragraph (3) shall prohibit a party from petitioning the 
14    Commission to rehear or appeal to the courts the order 
15    under the provisions of this Act.
16    (e) Beginning on June 1, 2017 (the effective date of 
17Public Act 99-906), a utility subject to the requirements of 
18this Section may elect to defer, as a regulatory asset, up to 
19the full amount of its expenditures incurred under this 
20Section for each annual period, including, but not limited to, 
21any expenditures incurred above the funding level set by 
22subsection (f) of this Section for a given year. The total 
23expenditures deferred as a regulatory asset in a given year 
24shall be amortized and recovered over a period that is equal to 
25the weighted average of the energy efficiency measure lives 
26implemented for that year that are reflected in the regulatory 
 
 
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1asset. The unamortized balance shall be recognized as of 
2December 31 for a given year. The utility shall also earn a 
3return on the total of the unamortized balances of all of the 
4energy efficiency regulatory assets, less any deferred taxes 
5related to those unamortized balances, at an annual rate equal 
6to the utility's weighted average cost of capital that 
7includes, based on a year-end capital structure, the utility's 
8actual cost of debt for the applicable calendar year and a cost 
9of equity, which shall be determined as set forth in 
10subparagraph (C) of paragraph (2) of subsection of this 
11Section calculated as the sum of the (i) the average for the 
12applicable calendar year of the monthly average yields of 
1330-year U.S. Treasury bonds published by the Board of 
14Governors of the Federal Reserve System in its weekly H.15 
15Statistical Release or successor publication; and (ii) 580 
16basis points, including a revenue conversion factor calculated 
17to recover or refund all additional income taxes that may be 
18payable or receivable as a result of that return. Capital 
19investment costs shall be depreciated and recovered over their 
20useful lives consistent with generally accepted accounting 
21principles. The weighted average cost of capital shall be 
22applied to the capital investment cost balance, less any 
23accumulated depreciation and accumulated deferred income 
24taxes, as of December 31 for a given year.
25    When an electric utility creates a regulatory asset under 
26the provisions of this Section, the costs are recovered over a 
 
 
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1period during which customers also receive a benefit which is 
2in the public interest. Accordingly, it is the intent of the 
3General Assembly that an electric utility that elects to 
4create a regulatory asset under the provisions of this Section 
5shall recover all of the associated costs as set forth in this 
6Section. After the Commission has approved the prudence and 
7reasonableness of the costs that comprise the regulatory 
8asset, the electric utility shall be permitted to recover all 
9such costs, and the value and recoverability through rates of 
10the associated regulatory asset shall not be limited, altered, 
11impaired, or reduced.
12    (f) Beginning in 2017, each electric utility shall file an 
13energy efficiency plan with the Commission to meet the energy 
14efficiency standards for the next applicable multi-year period 
15beginning January 1 of the year following the filing, 
16according to the schedule set forth in paragraphs (1) through 
17(3) of this subsection (f). If a utility does not file such a 
18plan on or before the applicable filing deadline for the plan, 
19it shall face a penalty of $100,000 per day until the plan is 
20filed.
21        (1) No later than 30 days after June 1, 2017 (the 
22    effective date of Public Act 99-906), each electric 
23    utility shall file a 4-year energy efficiency plan 
24    commencing on January 1, 2018 that is designed to achieve 
25    the cumulative persisting annual savings goals specified 
26    in paragraphs (1) through (4) of subsection (b-5) of this 
 
 
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1    Section or in paragraphs (1) through (4) of subsection 
2    (b-15) of this Section, as applicable, through 
3    implementation of energy efficiency measures; however, the 
4    goals may be reduced if the utility's expenditures are 
5    limited pursuant to subsection (m) of this Section or, for 
6    a utility that serves less than 3,000,000 retail 
7    customers, if each of the following conditions are met: 
8    (A) the plan's analysis and forecasts of the utility's 
9    ability to acquire energy savings demonstrate that 
10    achievement of such goals is not cost effective; and (B) 
11    the amount of energy savings achieved by the utility as 
12    determined by the independent evaluator for the most 
13    recent year for which savings have been evaluated 
14    preceding the plan filing was less than the average annual 
15    amount of savings required to achieve the goals for the 
16    applicable 4-year plan period. Except as provided in 
17    subsection (m) of this Section, annual increases in 
18    cumulative persisting annual savings goals during the 
19    applicable 4-year plan period shall not be reduced to 
20    amounts that are less than the maximum amount of 
21    cumulative persisting annual savings that is forecast to 
22    be cost-effectively achievable during the 4-year plan 
23    period. The Commission shall review any proposed goal 
24    reduction as part of its review and approval of the 
25    utility's proposed plan.
26        (2) No later than March 1, 2021, each electric utility 
 
 
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1    shall file a 4-year energy efficiency plan commencing on 
2    January 1, 2022 that is designed to achieve the cumulative 
3    persisting annual savings goals specified in paragraphs 
4    (5) through (8) of subsection (b-5) of this Section or in 
5    paragraphs (5) through (8) of subsection (b-15) of this 
6    Section, as applicable, through implementation of energy 
7    efficiency measures; however, the goals may be reduced if 
8    either (1) clear and convincing evidence demonstrates, 
9    through independent analysis, that the expenditure limits 
10    in subsection (m) of this Section preclude full 
11    achievement of the goals or (2) each of the following 
12    conditions are met: (A) the plan's analysis and forecasts 
13    of the utility's ability to acquire energy savings 
14    demonstrate by clear and convincing evidence and through 
15    independent analysis that achievement of such goals is not 
16    cost effective; and (B) the amount of energy savings 
17    achieved by the utility as determined by the independent 
18    evaluator for the most recent year for which savings have 
19    been evaluated preceding the plan filing was less than the 
20    average annual amount of savings required to achieve the 
21    goals for the applicable 4-year plan period. If there is 
22    not clear and convincing evidence that achieving the 
23    savings goals specified in paragraph (b-5) or (b-15) of 
24    this Section is possible both cost-effectively and within 
25    the expenditure limits in subsection (m), such savings 
26    goals shall not be reduced. Except as provided in 
 
 
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1    subsection (m) of this Section, annual increases in 
2    cumulative persisting annual savings goals during the 
3    applicable 4-year plan period shall not be reduced to 
4    amounts that are less than the maximum amount of 
5    cumulative persisting annual savings that is forecast to 
6    be cost-effectively achievable during the 4-year plan 
7    period. The Commission shall review any proposed goal 
8    reduction as part of its review and approval of the 
9    utility's proposed plan.
10        (2.5) Provisions of the multi-year plans for calendar 
11    years 2026 through 2029 that relate to calendar year 2026 
12    and that were filed by the electric utilities on February 
13    28, 2025 shall remain in effect through calendar year 
14    2026. Provisions of the plans for calendar years 2027 
15    through 2029 shall be modified and resubmitted to the 
16    Commission by the electric utilities pursuant to paragraph 
17    (3) of this subsection (f).    
18        (3) No later than March 1, 2026 or the effective date 
19    of this amendatory Act of the 104th General Assembly, 
20    whichever is later 2025, each electric utility shall file 
21    a 3-year 4-year energy efficiency plan commencing on 
22    January 1, 2027 2026 that is designed to achieve, through 
23    implementation of energy efficiency measures, lifetime 
24    energy equal to the product of the incremental annual 
25    savings goals defined by paragraph (1) of subsection 
26    (b-16) and the minimum average savings life defined by 
 
 
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1    paragraph (3) of subsection (b-16). The 3-year energy 
2    efficiency plan of a utility that serves less than 
3    3,000,000 retail customers but more than 500,000 retail 
4    customers in the State must also be designed to achieve 
5    lifetime peak demand savings equal to the product of the 
6    incremental annual savings goals defined by paragraph (2) 
7    of subsection (b-16) and the minimum average savings life 
8    defined by paragraph (3) of subsection (b-16) through 
9    implementation of energy efficiency measures. The savings 
10    goals may be reduced if: (i) clear and convincing evidence 
11    and independent analysis demonstrates that the expenditure 
12    limits in subsection (m) of this Section preclude full 
13    achievement of the goals, (ii) each of the following 
14    conditions are met: (A) the plan's analysis and forecasts 
15    of the utility's ability to acquire energy savings 
16    demonstrate by clear and convincing evidence and through 
17    independent analysis that achievement of such goals is not 
18    cost-effective; and (B) the amount of energy savings 
19    achieved by the utility, as determined by the independent 
20    evaluator, for the most recent year for which savings have 
21    been evaluated preceding the plan filing was less than the 
22    average annual amount of savings required to achieve the 
23    goals for the applicable multi-year plan period, or (iii) 
24    changes in federal law, programs, or tariffs have a 
25    significant and demonstrable impact on the cost of 
26    delivering measures and programs. If there is not clear 
 
 
10400SB0025ham002- 492 -LRB104 07069 AAS 28576 a

1    and convincing evidence that achieving the savings goals 
2    specified in subsection (b-16) is possible both 
3    cost-effectively and within the expenditure limits in 
4    subsection (m), such savings goals shall not be reduced. 
5    Except as provided in subsection (m), annual savings goals 
6    during the applicable multi-year plan period shall not be 
7    reduced to amounts that are less than the maximum amount 
8    of annual savings that is forecasted to be 
9    cost-effectively achievable during the applicable 
10    multi-year plan period. The Commission shall review any 
11    proposed goal reduction as part of its review and approval 
12    of the utility's proposed plan. the cumulative persisting 
13    annual savings goals specified in paragraphs (9) through 
14    (12) of subsection (b-5) of this Section or in paragraphs 
15    (9) through (12) of subsection (b-15) of this Section, as 
16    applicable, through implementation of energy efficiency 
17    measures; however, the goals may be reduced if either (1) 
18    clear and convincing evidence demonstrates, through 
19    independent analysis, that the expenditure limits in 
20    subsection (m) of this Section preclude full achievement 
21    of the goals or (2) each of the following conditions are 
22    met: (A) the plan's analysis and forecasts of the 
23    utility's ability to acquire energy savings demonstrate by 
24    clear and convincing evidence and through independent 
25    analysis that achievement of such goals is not cost 
26    effective; and (B) the amount of energy savings achieved 
 
 
10400SB0025ham002- 493 -LRB104 07069 AAS 28576 a

1    by the utility as determined by the independent evaluator 
2    for the most recent year for which savings have been 
3    evaluated preceding the plan filing was less than the 
4    average annual amount of savings required to achieve the 
5    goals for the applicable 4-year plan period. If there is 
6    not clear and convincing evidence that achieving the 
7    savings goals specified in paragraphs (b-5) or (b-15) of 
8    this Section is possible both cost-effectively and within 
9    the expenditure limits in subsection (m), such savings 
10    goals shall not be reduced. Except as provided in 
11    subsection (m) of this Section, annual increases in 
12    cumulative persisting annual savings goals during the 
13    applicable 4-year plan period shall not be reduced to 
14    amounts that are less than the maximum amount of 
15    cumulative persisting annual savings that is forecast to 
16    be cost-effectively achievable during the 4-year plan 
17    period. The Commission shall review any proposed goal 
18    reduction as part of its review and approval of the 
19    utility's proposed plan.    
20        (4) No later than March 1, 2029, and every 4 years 
21    thereafter, each electric utility shall file a 4-year 
22    energy efficiency plan commencing on January 1, 2030, and 
23    every 4 years thereafter, respectively, that is designed 
24    to achieve the cumulative persisting annual savings goals 
25    established by the Illinois Commerce Commission pursuant 
26    to direction of subsections (b-5) and (b-15) of this 
 
 
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1    Section, as applicable, through implementation of energy 
2    efficiency measures, lifetime energy equal to the product 
3    of the incremental annual savings goals defined by 
4    paragraph (1) of subsection (b-16) and the minimum average 
5    savings life described in paragraph (C) of subsection 
6    (b-16) of this Section. The 3-year energy efficiency plan 
7    of a utility that serves less than 3,000,000 retail 
8    customers but more than 500,000 retail customers in the 
9    State must also be designed to achieve lifetime peak 
10    demand savings equal to the product of the incremental 
11    annual savings goals defined by paragraph (2) of 
12    subsection (b-16) and the minimum average savings life 
13    defined by paragraph (3) of subsection (b-16) through 
14    implementation of energy efficiency measures. However ; 
15    however, the goals may be reduced if: either (1) clear and 
16    convincing evidence and independent analysis demonstrates 
17    that the expenditure limits in subsection (m) of this 
18    Section preclude full achievement of the goals, or (2) 
19    each of the following conditions are met: (A) the plan's 
20    analysis and forecasts of the utility's ability to acquire 
21    energy savings demonstrate by clear and convincing 
22    evidence and through independent analysis that achievement 
23    of such goals is not cost-effective; and (B) the amount of 
24    energy savings achieved by the utility as determined by 
25    the independent evaluator for the most recent year for 
26    which savings have been evaluated preceding the plan 
 
 
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1    filing was less than the average annual amount of savings 
2    required to achieve the goals for the applicable 
3    multi-year 4-year plan period, or (3) changes in federal 
4    law, programs, or tariffs have a significant and 
5    demonstrable impact on the cost of delivering measures and 
6    programs. If there is not clear and convincing evidence 
7    that achieving the savings goals specified in paragraph 
8    (b-16) paragraphs (b-5) or (b-15) of this Section is 
9    possible both cost-effectively and within the expenditure 
10    limits in subsection (m), such savings goals shall not be 
11    reduced. Except as provided in subsection (m) of this 
12    Section, annual increases in cumulative persisting annual 
13    savings goals during the applicable multi-year 4-year plan 
14    period shall not be reduced to amounts that are less than 
15    the maximum amount of cumulative persisting annual savings 
16    that is forecast to be cost-effectively achievable during 
17    the applicable multi-year 4-year plan period. The 
18    Commission shall review any proposed goal reduction as 
19    part of its review and approval of the utility's proposed 
20    plan.
21    Each utility's plan shall set forth the utility's 
22proposals to meet the energy efficiency standards identified 
23in subsection (b-5), or (b-15), or (b-16), as applicable and 
24as such standards may have been modified under this subsection 
25(f), taking into account the unique circumstances of the 
26utility's service territory. For those plans commencing on 
 
 
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1January 1, 2018, the Commission shall seek public comment on 
2the utility's plan and shall issue an order approving or 
3disapproving each plan no later than 105 days after June 1, 
42017 (the effective date of Public Act 99-906). For those 
5plans commencing after December 31, 2021, the Commission shall 
6seek public comment on the utility's plan and shall issue an 
7order approving or disapproving each plan within 6 months 
8after its submission. If the Commission disapproves a plan, 
9the Commission shall, within 30 days, describe in detail the 
10reasons for the disapproval and describe a path by which the 
11utility may file a revised draft of the plan to address the 
12Commission's concerns satisfactorily. If the utility does not 
13refile with the Commission within 60 days, the utility shall 
14be subject to penalties at a rate of $100,000 per day until the 
15plan is filed. This process shall continue, and penalties 
16shall accrue, until the utility has successfully filed a 
17portfolio of energy efficiency and demand-response measures. 
18Penalties shall be deposited into the Energy Efficiency Trust 
19Fund. 
20    (g) In submitting proposed plans and funding levels under 
21subsection (f) of this Section to meet the savings goals 
22identified in subsection (b-5), or (b-15), or (b-16) of this 
23Section, as applicable, the utility shall:
24        (1) Demonstrate that its proposed energy efficiency 
25    measures will achieve the applicable requirements that are 
26    identified in subsection (b-5), or (b-15), or (b-16) of 
 
 
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1    this Section, as modified by subsection (f) of this 
2    Section.
3        (2) (Blank).
4        (2.5) Demonstrate consideration of program options for 
5    (A) advancing new building codes, appliance standards, and 
6    municipal regulations governing existing and new building 
7    efficiency improvements and (B) supporting efforts to 
8    improve compliance with new building codes, appliance 
9    standards and municipal regulations, as potentially 
10    cost-effective means of acquiring energy savings to count 
11    toward savings goals. 
12        (3) Demonstrate that its overall portfolio of 
13    measures, not including low-income programs described in 
14    subsection (c) of this Section, is cost-effective using 
15    the total resource cost test or complies with paragraphs 
16    (1) through (3) of subsection (f) of this Section and 
17    represents a diverse cross-section of opportunities for 
18    customers of all rate classes, other than those customers 
19    described in subsection (l) of this Section, to 
20    participate in the programs. Individual measures need not 
21    be cost effective.
22        (3.5) Demonstrate that the utility's plan integrates 
23    the delivery of energy efficiency programs with natural 
24    gas efficiency programs, programs promoting distributed 
25    solar, programs promoting demand response and other 
26    efforts to address bill payment issues, including, but not 
 
 
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1    limited to, LIHEAP and the Percentage of Income Payment 
2    Plan, to the extent such integration is practical and has 
3    the potential to enhance customer engagement, minimize 
4    market confusion, or reduce administrative costs. 
5        (4) If the utility chooses, present Present a 
6    third-party energy efficiency implementation program 
7    subject to the following requirements:
8            (A) (blank); beginning with the year commencing 
9        January 1, 2019, electric utilities that serve more 
10        than 3,000,000 retail customers in the State shall 
11        fund third-party energy efficiency programs in an 
12        amount that is no less than $25,000,000 per year, and 
13        electric utilities that serve less than 3,000,000 
14        retail customers but more than 500,000 retail 
15        customers in the State shall fund third-party energy 
16        efficiency programs in an amount that is no less than 
17        $8,350,000 per year;
18            (B) during 2018, the utility shall conduct a 
19        solicitation process for purposes of requesting 
20        proposals from third-party vendors for those 
21        third-party energy efficiency programs to be offered 
22        during one or more of the years commencing January 1, 
23        2019, January 1, 2020, and January 1, 2021; for those 
24        multi-year plans commencing on January 1, 2022 and 
25        January 1, 2026, the utility shall conduct a 
26        solicitation process during 2021 and 2025, 
 
 
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1        respectively, for purposes of requesting proposals 
2        from third-party vendors for those third-party energy 
3        efficiency programs to be offered during one or more 
4        years of the respective multi-year plan period; for 
5        each solicitation process, the utility shall identify 
6        the sector, technology, or geographical area for which 
7        it is seeking requests for proposals; the solicitation 
8        process must be either for programs that fill gaps in 
9        the utility's program portfolio and for programs that 
10        target low-income customers, business sectors, 
11        building types, geographies, or other specific parts 
12        of its customer base with initiatives that would be 
13        more effective at reaching these customer segments 
14        than the utilities' programs filed in its energy 
15        efficiency plans;
16            (C) the utility shall propose the bidder 
17        qualifications, performance measurement process, and 
18        contract structure, which must include a performance 
19        payment mechanism and general terms and conditions; 
20        the proposed qualifications, process, and structure 
21        shall be subject to Commission approval; and
22            (D) the utility shall retain an independent third 
23        party to score the proposals received through the 
24        solicitation process described in this paragraph (4), 
25        rank them according to their cost per lifetime 
26        kilowatt-hours saved, and assemble the portfolio of 
 
 
10400SB0025ham002- 500 -LRB104 07069 AAS 28576 a

1        third-party programs.
2        The electric utility shall recover all costs 
3    associated with Commission-approved, third-party 
4    administered programs regardless of the success of those 
5    programs. 
6        (4.5) Implement cost-effective demand-response 
7    measures to reduce peak demand by 0.1% over the prior year 
8    for eligible retail customers, as defined in Section 
9    16-111.5 of this Act, and for customers that elect hourly 
10    service from the utility pursuant to Section 16-107 of 
11    this Act, provided those customers have not been declared 
12    competitive. This requirement continues until December 31, 
13    2026. 
14        (5) Include a proposed or revised cost-recovery tariff 
15    mechanism, as provided for under subsection (d) of this 
16    Section, to fund the proposed energy efficiency and 
17    demand-response measures and to ensure the recovery of the 
18    prudently and reasonably incurred costs of 
19    Commission-approved programs.
20        (6) Provide for an annual independent evaluation of 
21    the performance of the cost-effectiveness of the utility's 
22    portfolio of measures, as well as a full review of the 
23    multi-year plan results of the broader net program impacts 
24    and, to the extent practical, for adjustment of the 
25    measures on a going-forward basis as a result of the 
26    evaluations. The resources dedicated to evaluation shall 
 
 
10400SB0025ham002- 501 -LRB104 07069 AAS 28576 a

1    not exceed 3% of portfolio resources in any given year.
2        (7) For electric utilities that serve more than 
3    3,000,000 retail customers in the State:
4            (A) Through December 31, 2026 2025, provide for an 
5        adjustment to the return on equity component of the 
6        utility's weighted average cost of capital calculated 
7        under subsection (d) of this Section:
8                (i) If the independent evaluator determines 
9            that the utility achieved a cumulative persisting 
10            annual savings that is less than the applicable 
11            annual incremental goal, then the return on equity 
12            component shall be reduced by a maximum of 200 
13            basis points in the event that the utility 
14            achieved no more than 75% of such goal. If the 
15            utility achieved more than 75% of the applicable 
16            annual incremental goal but less than 100% of such 
17            goal, then the return on equity component shall be 
18            reduced by 8 basis points for each percent by 
19            which the utility failed to achieve the goal.
20                (ii) If the independent evaluator determines 
21            that the utility achieved a cumulative persisting 
22            annual savings that is more than the applicable 
23            annual incremental goal, then the return on equity 
24            component shall be increased by a maximum of 200 
25            basis points in the event that the utility 
26            achieved at least 125% of such goal. If the 
 
 
10400SB0025ham002- 502 -LRB104 07069 AAS 28576 a

1            utility achieved more than 100% of the applicable 
2            annual incremental goal but less than 125% of such 
3            goal, then the return on equity component shall be 
4            increased by 8 basis points for each percent by 
5            which the utility achieved above the goal. If the 
6            applicable annual incremental goal was reduced 
7            under paragraph (1) or (2) of subsection (f) of 
8            this Section, then the following adjustments shall 
9            be made to the calculations described in this item 
10            (ii):
11                    (aa) the calculation for determining 
12                achievement that is at least 125% of the 
13                applicable annual incremental goal shall use 
14                the unreduced applicable annual incremental 
15                goal to set the value; and
16                    (bb) the calculation for determining 
17                achievement that is less than 125% but more 
18                than 100% of the applicable annual incremental 
19                goal shall use the reduced applicable annual 
20                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 
24                also be modified, as necessary, so that the 
25                200 basis points are evenly apportioned among 
26                each percentage point value between 100% and 
 
 
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1                125% achievement.
2            (B) (Blank). For the period January 1, 2026 
3        through December 31, 2029 and in all subsequent 4-year 
4        periods, provide for an adjustment to the return on 
5        equity component of the utility's weighted average 
6        cost of capital calculated under subsection (d) of 
7        this Section:
8                (i) If the independent evaluator determines 
9            that the utility achieved a cumulative persisting 
10            annual savings that is less than the applicable 
11            annual incremental goal, then the return on equity 
12            component shall be reduced by a maximum of 200 
13            basis points in the event that the utility 
14            achieved no more than 66% of such goal. If the 
15            utility achieved more than 66% of the applicable 
16            annual incremental goal but less than 100% of such 
17            goal, then the return on equity component shall be 
18            reduced by 6 basis points for each percent by 
19            which the utility failed to achieve the goal.
20                (ii) If the independent evaluator determines 
21            that the utility achieved a cumulative persisting 
22            annual savings that is more than the applicable 
23            annual incremental goal, then the return on equity 
24            component shall be increased by a maximum of 200 
25            basis points in the event that the utility 
26            achieved at least 134% of such goal. If the 
 
 
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1            utility achieved more than 100% of the applicable 
2            annual incremental goal but less than 134% of such 
3            goal, then the return on equity component shall be 
4            increased by 6 basis points for each percent by 
5            which the utility achieved above the goal. If the 
6            applicable annual incremental goal was reduced 
7            under paragraph (3) of subsection (f) of this 
8            Section, then the following adjustments shall be 
9            made to the calculations described in this item 
10            (ii):
11                    (aa) the calculation for determining 
12                achievement that is at least 134% of the 
13                applicable annual incremental goal shall use 
14                the unreduced applicable annual incremental 
15                goal to set the value; and
16                    (bb) the calculation for determining 
17                achievement that is less than 134% but more 
18                than 100% of the applicable annual incremental 
19                goal shall use the reduced applicable annual 
20                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 134% 
23                achievement. The 6 basis point value shall 
24                also be modified, as necessary, so that the 
25                200 basis points are evenly apportioned among 
26                each percentage point value between 100% and 
 
 
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1                134% achievement. 
2            (C) (Blank). Notwithstanding the provisions of 
3        subparagraphs (A) and (B) of this paragraph (7), if 
4        the applicable annual incremental goal for an electric 
5        utility is ever less than 0.6% of deemed average 
6        weather normalized sales of electric power and energy 
7        during calendar years 2014, 2015, and 2016, an 
8        adjustment to the return on equity component of the 
9        utility's weighted average cost of capital calculated 
10        under subsection (d) of this Section shall be made as 
11        follows:
12                (i) If the independent evaluator determines 
13            that the utility achieved a cumulative persisting 
14            annual savings that is less than would have been 
15            achieved had the applicable annual incremental 
16            goal been achieved, then the return on equity 
17            component shall be reduced by a maximum of 200 
18            basis points if the utility achieved no more than 
19            75% of its applicable annual total savings 
20            requirement as defined in paragraph (7.5) of this 
21            subsection. If the utility achieved more than 75% 
22            of the applicable annual total savings requirement 
23            but less than 100% of such goal, then the return on 
24            equity component shall be reduced by 8 basis 
25            points for each percent by which the utility 
26            failed to achieve the goal.
 
 
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1                (ii) If the independent evaluator determines 
2            that the utility achieved a cumulative persisting 
3            annual savings that is more than would have been 
4            achieved had the applicable annual incremental 
5            goal been achieved, then the return on equity 
6            component shall be increased by a maximum of 200 
7            basis points if the utility achieved at least 125% 
8            of its applicable annual total savings 
9            requirement. If the utility achieved more than 
10            100% of the applicable annual total savings 
11            requirement but less than 125% of such goal, then 
12            the return on equity component shall be increased 
13            by 8 basis points for each percent by which the 
14            utility achieved above the applicable annual total 
15            savings requirement. If the applicable annual 
16            incremental goal was reduced under paragraph (1) 
17            or (2) of subsection (f) of this Section, then the 
18            following adjustments shall be made to the 
19            calculations described in this item (ii):
20                    (aa) the calculation for determining 
21                achievement that is at least 125% of the 
22                applicable annual total savings requirement 
23                shall use the unreduced applicable annual 
24                incremental goal to set the value; and
25                    (bb) the calculation for determining 
26                achievement that is less than 125% but more 
 
 
10400SB0025ham002- 507 -LRB104 07069 AAS 28576 a

1                than 100% of the applicable annual total 
2                savings requirement shall use the reduced 
3                applicable annual incremental goal to set the 
4                value for 100% achievement of the goal and 
5                shall use the unreduced goal to set the value 
6                for 125% achievement. The 8 basis point value 
7                shall also be modified, as necessary, so that 
8                the 200 basis points are evenly apportioned 
9                among each percentage point value between 100% 
10                and 125% achievement. 
11        (7.5) For purposes of this Section, the term 
12    "applicable annual incremental goal" means the difference 
13    between the cumulative persisting annual savings goal for 
14    the calendar year that is the subject of the independent 
15    evaluator's determination and the cumulative persisting 
16    annual savings goal for the immediately preceding calendar 
17    year, as such goals are defined in subsections (b-5) and 
18    (b-15) of this Section and as these goals may have been 
19    modified as provided for under subsection (b-20) and 
20    paragraphs (1) and (2) through (3) of subsection (f) of 
21    this Section. Under subsections (b), (b-5), (b-10), and 
22    (b-15) of this Section, a utility must first replace 
23    energy savings from measures that have expired before any 
24    progress towards achievement of its applicable annual 
25    incremental goal may be counted. Savings may expire 
26    because measures installed in previous years have reached 
 
 
10400SB0025ham002- 508 -LRB104 07069 AAS 28576 a

1    the end of their lives, because measures installed in 
2    previous years are producing lower savings in the current 
3    year than in the previous year, or for other reasons 
4    identified by independent evaluators. Notwithstanding 
5    anything else set forth in this Section, the difference 
6    between the actual annual incremental savings achieved in 
7    any given year, including the replacement of energy 
8    savings that have expired, and the applicable annual 
9    incremental goal shall not affect adjustments to the 
10    return on equity for subsequent calendar years under this 
11    subsection (g). 
12        In this Section, "applicable annual total savings 
13    requirement" means the total amount of new annual savings 
14    that the utility must achieve in any given year to achieve 
15    the applicable annual incremental goal. This is equal to 
16    the applicable annual incremental goal plus the total new 
17    annual savings that are required to replace savings that 
18    expired in or at the end of the previous year. 
19        (8) For electric utilities that serve less than 
20    3,000,000 retail customers but more than 500,000 retail 
21    customers in the State:
22            (A) Through December 31, 2026 2025, the applicable 
23        annual incremental goal shall be compared to the 
24        annual incremental savings as determined by the 
25        independent evaluator.
26                (i) The return on equity component shall be 
 
 
10400SB0025ham002- 509 -LRB104 07069 AAS 28576 a

1            reduced by 8 basis points for each percent by 
2            which the utility did not achieve 84.4% of the 
3            applicable annual incremental goal.
4                (ii) The return on equity component shall be 
5            increased by 8 basis points for each percent by 
6            which the utility exceeded 100% of the applicable 
7            annual incremental goal.
8                (iii) The return on equity component shall not 
9            be increased or decreased if the annual 
10            incremental savings as determined by the 
11            independent evaluator is greater than 84.4% of the 
12            applicable annual incremental goal and less than 
13            100% of the applicable annual incremental goal.
14                (iv) The return on equity component shall not 
15            be increased or decreased by an amount greater 
16            than 200 basis points pursuant to this 
17            subparagraph (A).
18            (B) (Blank). For the period of January 1, 2026 
19        through December 31, 2029 and in all subsequent 4-year 
20        periods, the applicable annual incremental goal shall 
21        be compared to the annual incremental savings as 
22        determined by the independent evaluator.
23                (i) The return on equity component shall be 
24            reduced by 6 basis points for each percent by 
25            which the utility did not achieve 100% of the 
26            applicable annual incremental goal.
 
 
10400SB0025ham002- 510 -LRB104 07069 AAS 28576 a

1                (ii) The return on equity component shall be 
2            increased by 6 basis points for each percent by 
3            which the utility exceeded 100% of the applicable 
4            annual incremental goal.
5                (iii) The return on equity component shall not 
6            be increased or decreased by an amount greater 
7            than 200 basis points pursuant to this 
8            subparagraph (B).
9            (C) (Blank). Notwithstanding provisions in 
10        subparagraphs (A) and (B) of paragraph (7) of this 
11        subsection, if the applicable annual incremental goal 
12        for an electric utility is ever less than 0.6% of 
13        deemed average weather normalized sales of electric 
14        power and energy during calendar years 2014, 2015 and 
15        2016, an adjustment to the return on equity component 
16        of the utility's weighted average cost of capital 
17        calculated under subsection (d) of this Section shall 
18        be made as follows:
19                (i) The return on equity component shall be 
20            reduced by 8 basis points for each percent by 
21            which the utility did not achieve 100% of the 
22            applicable annual total savings requirement.
23                (ii) The return on equity component shall be 
24            increased by 8 basis points for each percent by 
25            which the utility exceeded 100% of the applicable 
26            annual total savings requirement.
 
 
10400SB0025ham002- 511 -LRB104 07069 AAS 28576 a

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 (C). 
5            (D) (Blank). If the applicable annual incremental 
6        goal was reduced under paragraph (1), (2), (3), or (4) 
7        of subsection (f) of this Section, then the following 
8        adjustments shall be made to the calculations 
9        described in subparagraphs (A), (B), and (C) of this 
10        paragraph (8):
11                (i) The calculation for determining 
12            achievement that is at least 125% or 134%, as 
13            applicable, of the applicable annual incremental 
14            goal or the applicable annual total savings 
15            requirement, as applicable, shall use the 
16            unreduced applicable annual incremental goal to 
17            set the value.
18                (ii) For the period through December 31, 2025, 
19            the calculation for determining achievement that 
20            is less than 125% but more than 100% of the 
21            applicable annual incremental goal or the 
22            applicable annual total savings requirement, as 
23            applicable, shall use the reduced applicable 
24            annual incremental goal to set the value for 100% 
25            achievement of the goal and shall use the 
26            unreduced goal to set the value for 125% 
 
 
10400SB0025ham002- 512 -LRB104 07069 AAS 28576 a

1            achievement. The 8 basis point value shall also be 
2            modified, as necessary, so that the 200 basis 
3            points are evenly apportioned among each 
4            percentage point value between 100% and 125% 
5            achievement.
6                (iii) For the period of January 1, 2026 
7            through December 31, 2029 and all subsequent 
8            4-year periods, the calculation for determining 
9            achievement that is less than 125% or 134%, as 
10            applicable, but more than 100% of the applicable 
11            annual incremental goal or the applicable annual 
12            total savings requirement, as applicable, shall 
13            use the reduced applicable annual incremental goal 
14            to set the value for 100% achievement of the goal 
15            and shall use the unreduced goal to set the value 
16            for 125% achievement. The 6 basis-point value or 8 
17            basis-point value, as applicable, shall also be 
18            modified, as necessary, so that the 200 basis 
19            points are evenly apportioned among each 
20            percentage point value between 100% and 125% or 
21            between 100% and 134% achievement, as applicable.
22        (8.5) Beginning January 1, 2027, a utility that serves 
23    greater than 500,000 retail customers in the State shall 
24    have the utility's return on equity modified for 
25    performance on the utility's energy savings and peak 
26    demand savings goals as follows:
 
 
10400SB0025ham002- 513 -LRB104 07069 AAS 28576 a

1            (A) The return on equity for a utility that serves 
2        more than 3,000,000 retail customers in the State may 
3        be adjusted up or down by a maximum of 200 basis points 
4        for its performance relative to its incremental annual 
5        energy savings goal. The return on equity for a 
6        utility that serves less than 3,000,000 retail 
7        customers but more than 500,000 retail customers in 
8        the State may be adjusted up or down by a maximum of 
9        100 basis points for its performance relative to its 
10        incremental annual energy savings goal and a maximum 
11        of 100 basis points for its performance relative to 
12        its incremental annual coincident peak demand savings 
13        goal.
14            (B) A utility's performance on its savings goals 
15        shall be established by comparing the actual lifetime 
16        energy, and coincident peak demand savings if a 
17        utility serves less than 3,000,000 retail customers 
18        but more than 500,000 retail customers in the State, 
19        achieved from efficiency measures installed in a given 
20        year to the product of the incremental annual goals 
21        established in paragraphs (1) and (2) of subsection 
22        (b-16) and the minimum average savings lives 
23        established in paragraph (3) of subsection (b-16), as 
24        modified, if applicable, by the Commission under 
25        paragraph (4) of subsection (f) of this Section. For 
26        the purposes of this paragraph (8.5), "lifetime 
 
 
10400SB0025ham002- 514 -LRB104 07069 AAS 28576 a

1        savings" means the total incremental savings that 
2        installed efficiency measures are projected to 
3        produce, relative to what would have occurred absent 
4        to the utility's efficiency programs, over the useful 
5        lives of the measures. Performance on the energy 
6        savings goal, and coincident peak demand savings if a 
7        utility serves less than 3,000,000 retail customers 
8        but more than 500,000 retail customers in the State, 
9        shall be assessed separately, such that it is possible 
10        to earn penalties on both, earn bonuses on both, or 
11        earn a bonus for performance on one goal and a penalty 
12        on the other.
13            (C) No bonus shall be earned if a utility does not 
14        achieve greater than 100% of an approved goal. The 
15        maximum bonus for a goal shall be earned if the utility 
16        achieves 125% of the unmodified goal. For a utility 
17        that serves less than 3,000,000 retail customers but 
18        more than 500,000 retail customers in the State, the 
19        bonus earned for achieving more than 100% of an 
20        approved goal but less than 125% of the unmodified 
21        goal shall be linearly interpolated. For a utility 
22        with more than 3,000,000 retail customers, the maximum 
23        bonus for a goal shall be earned if the utility 
24        achieves 125% of the unmodified goal. For a utility 
25        with more than 3,000,000 retail customers, the bonus 
26        earned for achieving more than 100% of an approved 
 
 
10400SB0025ham002- 515 -LRB104 07069 AAS 28576 a

1        goal but less than 125% of the unmodified goal shall be 
2        linearly interpolated.
3            (D) For utilities with greater than 3,000,000 
4        retail customers, the return on equity shall be 
5        unmodified due to performance on an individual goal 
6        only if the utility achieves exactly 100% of the goal. 
7        For utilities with more than 500,000 but fewer than 
8        3,000,000 retail customers, the return on equity shall 
9        be unmodified for achieving between 85% and 100% of 
10        the goal.
11            (E) Penalties may be earned for falling short of 
12        goals, with the magnitude of any penalty being a 
13        function of both the size of the utility and whether 
14        goals established in subsection (b-16) are modified by 
15        the Commission under paragraph (4) of subsection (f) 
16        of this Section, as follows:
17                (i) If the savings goals specified in 
18            subsection (b-16) of this Section are unmodified, 
19            a utility with more than 3,000,000 retail 
20            customers shall earn the maximum penalty allocated 
21            to a goal for achieving 75% or less of the goal. 
22            The penalty for achieving greater than 75% but 
23            less than 100% of the goal shall be linearly 
24            interpolated.
25                (ii) If the savings goals specified in 
26            subsection (b-16) of this Section are unmodified, 
 
 
10400SB0025ham002- 516 -LRB104 07069 AAS 28576 a

1            a utility with more than 500,000 but fewer than 
2            3,000,000 retail customers shall earn the maximum 
3            penalty allocated to a goal for achieving at least 
4            33.3 percentage points less than the bottom end of 
5            the deadband specified in subparagraph (D) of this 
6            paragraph (8.5). The penalty for achieving less 
7            than the bottom end of the deadband and greater 
8            than 33.3 percentage points less than the bottom 
9            end of the deadband shall be linearly 
10            interpolated.
11                (iii) If either the energy or peak demand 
12            savings goals specified in subsection (b-16) are 
13            reduced under paragraph (3) or (4) of subsection 
14            (f) of this Section, the maximum penalty allocated 
15            to a goal shall be earned if the utility achieves 
16            80% or less of the modified goal. The penalty for 
17            achieving more than 80% but less than 100% of a 
18            modified goal shall be linearly interpolated.    
19        (9) The utility shall submit the energy savings data 
20    to the independent evaluator no later than 30 days after 
21    the close of the plan year. The independent evaluator 
22    shall determine the cumulative persisting annual savings 
23    and annual incremental savings for a given plan year, as 
24    well as an estimate of job impacts and other macroeconomic 
25    impacts of the efficiency programs for that year, no later 
26    than 120 days after the close of the plan year. The utility 
 
 
10400SB0025ham002- 517 -LRB104 07069 AAS 28576 a

1    shall submit an informational filing to the Commission no 
2    later than 160 days after the close of the plan year that 
3    attaches the independent evaluator's final report 
4    identifying the cumulative persisting annual savings for 
5    the year and calculates, under paragraph (7) or (8) of 
6    this subsection (g), as applicable, any resulting change 
7    to the utility's return on equity component of the 
8    weighted average cost of capital applicable to the next 
9    plan year beginning with the January monthly billing 
10    period and extending through the December monthly billing 
11    period. However, if the utility recovers the costs 
12    incurred under this Section under paragraphs (2) and (3) 
13    of subsection (d) of this Section, then the utility shall 
14    not be required to submit such informational filing, and 
15    shall instead submit the information that would otherwise 
16    be included in the informational filing as part of its 
17    filing under paragraph (3) of such subsection (d) that is 
18    due on or before June 1 of each year.
19        For those utilities that must submit the informational 
20    filing, the Commission may, on its own motion or by 
21    petition, initiate an investigation of such filing, 
22    provided, however, that the utility's proposed return on 
23    equity calculation shall be deemed the final, approved 
24    calculation on December 15 of the year in which it is filed 
25    unless the Commission enters an order on or before 
26    December 15, after notice and hearing, that modifies such 
 
 
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1    calculation consistent with this Section.
2        The adjustments to the return on equity component 
3    described in paragraphs (7) and (8) of this subsection (g) 
4    shall be applied as described in such paragraphs through a 
5    separate tariff mechanism, which shall be filed by the 
6    utility under subsections (f) and (g) of this Section. 
7        (9.5) The utility must demonstrate how it will ensure 
8    that program implementation contractors and energy 
9    efficiency installation vendors will promote workforce 
10    equity and quality jobs. For all construction, 
11    installation, or other related services procured under 
12    this Section, an electric utility must:
13            (A) award a bid preference of 2% to a contractor if 
14        the contractor certifies under oath that the 
15        contractor's primary place of business is located 
16        within the utility's service area; and
17            (B) award a bid preference of 2% to a contractor if 
18        the contractor certifies under oath that at least 85% 
19        of the workforce to be utilized for such construction, 
20        installation, or other related services reside in the 
21        utility's service area.    
22        (9.6) Utilities shall collect data necessary to ensure 
23    compliance with paragraph (9.5) no less than quarterly and 
24    shall communicate progress toward compliance with 
25    paragraph (9.5) to program implementation contractors and 
26    energy efficiency installation vendors no less than 
 
 
10400SB0025ham002- 519 -LRB104 07069 AAS 28576 a

1    quarterly. Utilities shall work with relevant vendors, 
2    providing education, training, and other resources needed 
3    to ensure compliance and, where necessary, adjusting or 
4    terminating work with vendors that cannot assist with 
5    compliance.
6        (10) Utilities required to implement efficiency 
7    programs under subsections (b-5), and (b-10), and (b-16)    
8    shall report annually to the Illinois Commerce Commission 
9    and the General Assembly on how hiring, contracting, job 
10    training, and other practices related to its energy 
11    efficiency programs enhance the diversity of vendors 
12    working on such programs. These reports must include data 
13    on vendor and employee diversity, including data on the 
14    implementation of paragraphs (9.5) and (9.6) and the 
15    proportion of total program dollars awarded to firms that 
16    meet the criteria of subparagraphs (A) and (B) of 
17    paragraph (9.5). If the utility is not meeting the 
18    requirements of paragraphs (9.5) and (9.6), the utility 
19    shall submit a plan to adjust their activities so that 
20    they meet the requirements of paragraphs (9.5) and (9.6) 
21    within the following year.
22    (h) No more than 4% of energy efficiency and 
23demand-response program revenue may be allocated for research, 
24development, or pilot deployment of new equipment or measures. 
25Electric utilities shall work with interested stakeholders to 
26formulate a plan for how these funds should be spent, 
 
 
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1incorporate statewide approaches for these allocations, and 
2file a 4-year plan that demonstrates that collaboration. If a 
3utility files a request for modified annual energy savings 
4goals with the Commission, then a utility shall forgo spending 
5portfolio dollars on research and development proposals. 
6    (i) When practicable, electric utilities shall incorporate 
7advanced metering infrastructure data into the planning, 
8implementation, and evaluation of energy efficiency measures 
9and programs, subject to the data privacy and confidentiality 
10protections of applicable law.
11    (j) The independent evaluator shall follow the guidelines 
12and use the savings set forth in Commission-approved energy 
13efficiency policy manuals and technical reference manuals, as 
14each may be updated from time to time. Until such time as 
15measure life values for energy efficiency measures implemented 
16for low-income households under subsection (c) of this Section 
17are incorporated into such Commission-approved manuals, the 
18low-income measures shall have the same measure life values 
19that are established for same measures implemented in 
20households that are not low-income households.
21    (k) Notwithstanding any provision of law to the contrary, 
22an electric utility subject to the requirements of this 
23Section may file a tariff cancelling an automatic adjustment 
24clause tariff in effect under this Section or Section 8-103, 
25which shall take effect no later than one business day after 
26the date such tariff is filed. Thereafter, the utility shall 
 
 
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1be authorized to defer and recover its expenditures incurred 
2under this Section through a new tariff authorized under 
3subsection (d) of this Section or in the utility's next rate 
4case under Article IX or Section 16-108.5 of this Act, with 
5interest at an annual rate equal to the utility's weighted 
6average cost of capital as approved by the Commission in such 
7case. If the utility elects to file a new tariff under 
8subsection (d) of this Section, the utility may file the 
9tariff within 10 days after June 1, 2017 (the effective date of 
10Public Act 99-906), and the cost inputs to such tariff shall be 
11based on the projected costs to be incurred by the utility 
12during the calendar year in which the new tariff is filed and 
13that were not recovered under the tariff that was cancelled as 
14provided for in this subsection. Such costs shall include 
15those incurred or to be incurred by the utility under its 
16multi-year plan approved under subsections (f) and (g) of this 
17Section, including, but not limited to, projected capital 
18investment costs and projected regulatory asset balances with 
19correspondingly updated depreciation and amortization reserves 
20and expense. The Commission shall, after notice and hearing, 
21approve, or approve with modification, such tariff and cost 
22inputs no later than 75 days after the utility filed the 
23tariff, provided that such approval, or approval with 
24modification, shall be consistent with the provisions of this 
25Section to the extent they do not conflict with this 
26subsection (k). The tariff approved by the Commission shall 
 
 
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1take effect no later than 5 days after the Commission enters 
2its order approving the tariff.
3    No later than 60 days after the effective date of the 
4tariff cancelling the utility's automatic adjustment clause 
5tariff, the utility shall file a reconciliation that 
6reconciles the moneys collected under its automatic adjustment 
7clause tariff with the costs incurred during the period 
8beginning June 1, 2016 and ending on the date that the electric 
9utility's automatic adjustment clause tariff was cancelled. In 
10the event the reconciliation reflects an under-collection, the 
11utility shall recover the costs as specified in this 
12subsection (k). If the reconciliation reflects an 
13over-collection, the utility shall apply the amount of such 
14over-collection as a one-time credit to retail customers' 
15bills.
16    (l) For the calendar years covered by a multi-year plan 
17commencing after December 31, 2017, subsections (a) through 
18(j) of this Section do not apply to eligible large private 
19energy customers that have chosen to opt out of multi-year 
20plans consistent with this subsection (1).
21        (1) For purposes of this subsection (l), "eligible 
22    large private energy customer" means any retail customers, 
23    except for federal, State, municipal, and other public 
24    customers, of an electric utility that serves more than 
25    3,000,000 retail customers, except for federal, State, 
26    municipal and other public customers, in the State and 
 
 
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1    whose total highest 30 minute demand was more than 10,000 
2    kilowatts, or any retail customers of an electric utility 
3    that serves less than 3,000,000 retail customers but more 
4    than 500,000 retail customers in the State and whose total 
5    highest 15 minute demand was more than 10,000 kilowatts. 
6    For purposes of this subsection (l), "retail customer" has 
7    the meaning set forth in Section 16-102 of this Act. 
8    However, for a business entity with multiple sites located 
9    in the State, where at least one of those sites qualifies 
10    as an eligible large private energy customer, then any of 
11    that business entity's sites, properly identified on a 
12    form for notice, shall be considered eligible large 
13    private energy customers for the purposes of this 
14    subsection (l). A determination of whether this subsection 
15    is applicable to a customer shall be made for each 
16    multi-year plan beginning after December 31, 2017. The 
17    criteria for determining whether this subsection (l) is 
18    applicable to a retail customer shall be based on the 12 
19    consecutive billing periods prior to the start of the 
20    first year of each such multi-year plan.
21        (2) Within 45 days after September 15, 2021 (the 
22    effective date of Public Act 102-662), the Commission 
23    shall prescribe the form for notice required for opting 
24    out of energy efficiency programs. The notice must be 
25    submitted to the retail electric utility 12 months before 
26    the next energy efficiency planning cycle. However, within 
 
 
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1    120 days after the Commission's initial issuance of the 
2    form for notice, eligible large private energy customers 
3    may submit a form for notice to an electric utility. The 
4    form for notice for opting out of energy efficiency 
5    programs shall include all of the following:
6            (A) a statement indicating that the customer has 
7        elected to opt out;
8            (B) the account numbers for the customer accounts 
9        to which the opt out shall apply;
10            (C) the mailing address associated with the 
11        customer accounts identified under subparagraph (B);
12            (D) an American Society of Heating, Refrigerating, 
13        and Air-Conditioning Engineers (ASHRAE) level 2 or 
14        higher audit report conducted by an independent 
15        third-party expert identifying cost-effective energy 
16        efficiency project opportunities that could be 
17        invested in over the next 10 years. A retail customer 
18        with specialized processes may utilize a self-audit 
19        process in lieu of the ASHRAE audit;
20            (E) a description of the customer's plans to 
21        reallocate the funds toward internal energy efficiency 
22        efforts identified in the subparagraph (D) report, 
23        including, but not limited to: (i) strategic energy 
24        management or other programs, including descriptions 
25        of targeted buildings, equipment and operations; (ii) 
26        eligible energy efficiency measures; and (iii) 
 
 
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1        expected energy savings, itemized by technology. If 
2        the subparagraph (D) audit report identifies that the 
3        customer currently utilizes the best available energy 
4        efficient technology, equipment, programs, and 
5        operations, the customer may provide a statement that 
6        more efficient technology, equipment, programs, and 
7        operations are not reasonably available as a means of 
8        satisfying this subparagraph (E); and
9            (F) the effective date of the opt out, which will 
10        be the next January 1 following notice of the opt out.
11        (3) Upon receipt of a properly and timely noticed 
12    request for opt out submitted by an eligible large private 
13    energy customer, the retail electric utility shall grant 
14    the request, file the request with the Commission and, 
15    beginning January 1 of the following year, the opted out 
16    customer shall no longer be assessed the costs of the plan 
17    and shall be prohibited from participating in that 4-year 
18    plan cycle to give the retail utility the certainty to 
19    design program plan proposals.
20        (4) Upon a customer's election to opt out under 
21    paragraphs (1) and (2) of this subsection (l) and 
22    commencing on the effective date of said opt out, the 
23    account properly identified in the customer's notice under 
24    paragraph (2) shall not be subject to any cost recovery 
25    and shall not be eligible to participate in, or directly 
26    benefit from, compliance with energy efficiency cumulative 
 
 
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1    persisting savings requirements under subsections (a) 
2    through (j).
3        (5) A utility's cumulative persisting annual savings 
4    targets will exclude any opted out load.
5        (6) The request to opt out is only valid for the 
6    requested plan cycle. An eligible large private energy 
7    customer must also request to opt out for future energy 
8    plan cycles, otherwise the customer will be included in 
9    the future energy plan cycle. 
10    (m) Notwithstanding the requirements of this Section, as 
11part of a proceeding to approve a multi-year plan under 
12subsections (f) and (g) of this Section if the multi-year plan 
13has been designed to maximize savings, but does not meet the 
14cost cap limitations of this Section, the Commission shall 
15reduce the amount of energy efficiency measures implemented 
16for any single year, and whose costs are recovered under 
17subsection (d) of this Section, by an amount necessary to 
18limit the estimated average net increase due to the cost of the 
19measures to no more than
20        (1) 3.5% for each of the 4 years beginning January 1, 
21    2018,
22        (2) (blank),
23        (3) 4% for each of the 4 years beginning January 1, 
24    2022,
25        (3.5) 4.25% for 2026,    
26        (4) 4.25% for electric utilities that serve more than 
 
 
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1    3,000,000 retail customers in the State, and 4.21% for 
2    2027, 5.25% for 2028, and 6.06% for 2029 for electric 
3    utilities with less than 3,000,000 retail customers but 
4    more than 500,000 retail customers in the State, for the 3    
5    4 years beginning January 1, 2027 2026, and
6        (5) the percentage specified in paragraph (4) 
7    applicable to 2029 4.25% plus an increase sufficient to 
8    account for the rate of inflation between January 1, 2027    
9    2026 and January 1 of the first year of each subsequent 
10    4-year plan cycle, 
11of the average amount paid per kilowatthour by residential 
12eligible retail customers during calendar year 2015 for plans 
13in effect through 2026 and during calendar year 2023 for plans 
14commencing in 2027 and thereafter. An electric utility may 
15plan to spend up to 10% more in any year during an applicable 
16multi-year plan period, including any transition period 
17authorized under paragraph (2.5) of subsection (f), to 
18cost-effectively achieve additional savings so long as the 
19average over the applicable multi-year plan period, which 
20shall include any transition period, does not exceed the 
21percentages defined in items (1) through (5). To determine the 
22total amount that may be spent by an electric utility in any 
23single year, the applicable percentage of the average amount 
24paid per kilowatthour shall be multiplied by the total amount 
25of energy delivered by such electric utility in the calendar 
26year 2015 for plans in effect through 2026 and during calendar 
 
 
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1year 2023 for plans commencing in 2027 and thereafter, 
2adjusted to reflect the proportion of the utility's load 
3attributable to customers that have opted out of subsections 
4(a) through (j) of this Section under subsection (l) of this 
5Section. For purposes of this subsection (m), the amount paid 
6per kilowatthour includes, without limitation, estimated 
7amounts paid for supply, transmission, distribution, 
8surcharges, and add-on taxes. For purposes of this Section, 
9"eligible retail customers" shall have the meaning set forth 
10in Section 16-111.5 of this Act. Once the Commission has 
11approved a plan under subsections (f) and (g) of this Section, 
12no subsequent rate impact determinations shall be made.
13    (n) A utility shall take advantage of the efficiencies 
14available through existing Illinois Home Weatherization 
15Assistance Program infrastructure and services, such as 
16enrollment, marketing, quality assurance and implementation, 
17which can reduce the need for similar services at a lower cost 
18than utility-only programs, subject to capacity constraints at 
19community action agencies, for both single-family and 
20multifamily weatherization services, to the extent Illinois 
21Home Weatherization Assistance Program community action 
22agencies provide multifamily services. A utility's plan shall 
23demonstrate that in formulating annual weatherization budgets, 
24it has sought input and coordination with community action 
25agencies regarding agencies' capacity to expand and maximize 
26Illinois Home Weatherization Assistance Program delivery using 
 
 
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1the ratepayer dollars collected under this Section. 
2(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23; 
3103-613, eff. 7-1-24.)
 
4    (220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
5    Sec. 8-406. Certificate of public convenience and 
6necessity. 
7    (a) No public utility not owning any city or village 
8franchise nor engaged in performing any public service or in 
9furnishing any product or commodity within this State as of 
10July 1, 1921 and not possessing a certificate of public 
11convenience and necessity from the Illinois Commerce 
12Commission, the State Public Utilities Commission, or the 
13Public Utilities Commission, at the time Public Act 84-617 
14goes into effect (January 1, 1986), shall transact any 
15business in this State until it shall have obtained a 
16certificate from the Commission that public convenience and 
17necessity require the transaction of such business. A 
18certificate of public convenience and necessity requiring the 
19transaction of public utility business in any area of this 
20State shall include authorization to the public utility 
21receiving the certificate of public convenience and necessity 
22to construct such plant, equipment, property, or facility as 
23is provided for under the terms and conditions of its tariff 
24and as is necessary to provide utility service and carry out 
25the transaction of public utility business by the public 
 
 
10400SB0025ham002- 530 -LRB104 07069 AAS 28576 a

1utility in the designated area.
2    (b) No public utility shall begin the construction of any 
3new plant, equipment, property, or facility which is not in 
4substitution of any existing plant, equipment, property, or 
5facility, or any extension or alteration thereof or in 
6addition thereto, unless and until it shall have obtained from 
7the Commission a certificate that public convenience and 
8necessity require such construction. Whenever after a hearing 
9the Commission determines that any new construction or the 
10transaction of any business by a public utility will promote 
11the public convenience and is necessary thereto, it shall have 
12the power to issue certificates of public convenience and 
13necessity. The Commission shall determine that proposed 
14construction will promote the public convenience and necessity 
15only if the utility demonstrates: (1) that the proposed 
16construction is necessary to provide adequate, reliable, and 
17efficient service to its customers and is the least-cost means 
18of satisfying the service needs of its customers or that the 
19proposed construction will promote the development of an 
20effectively competitive electricity market that operates 
21efficiently, is equitable to all customers, and is the 
22least-cost least cost means of satisfying those objectives; 
23(2) that the utility is capable of efficiently managing and 
24supervising the construction process and has taken sufficient 
25action to ensure adequate and efficient construction and 
26supervision thereof; and (3) that the utility is capable of 
 
 
10400SB0025ham002- 531 -LRB104 07069 AAS 28576 a

1financing the proposed construction without significant 
2adverse financial consequences for the utility or its 
3customers.
4    (b-5) As used in this subsection (b-5):
5    "Qualifying direct current applicant" means an entity that 
6seeks to provide direct current bulk transmission service for 
7the purpose of transporting electric energy in interstate 
8commerce.
9    "Qualifying direct current project" means a high voltage 
10direct current electric service line that crosses at least one 
11Illinois border, the Illinois portion of which is physically 
12located within the region of the Midcontinent Independent 
13System Operator, Inc., or its successor organization, and runs 
14through the counties of Pike, Scott, Greene, Macoupin, 
15Montgomery, Christian, Shelby, Cumberland, and Clark, is 
16capable of transmitting electricity at voltages of 345 
17kilovolts or above, and may also include associated 
18interconnected alternating current interconnection facilities 
19in this State that are part of the proposed project and 
20reasonably necessary to connect the project with other 
21portions of the grid.
22    Notwithstanding any other provision of this Act, a 
23qualifying direct current applicant that does not own, 
24control, operate, or manage, within this State, any plant, 
25equipment, or property used or to be used for the transmission 
26of electricity at the time of its application or of the 
 
 
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1Commission's order may file an application on or before 
2December 31, 2023 with the Commission pursuant to this Section 
3or Section 8-406.1 for, and the Commission may grant, a 
4certificate of public convenience and necessity to construct, 
5operate, and maintain a qualifying direct current project. The 
6qualifying direct current applicant may also include in the 
7application requests for authority under Section 8-503. The 
8Commission shall grant the application for a certificate of 
9public convenience and necessity and requests for authority 
10under Section 8-503 if it finds that the qualifying direct 
11current applicant and the proposed qualifying direct current 
12project satisfy the requirements of this subsection and 
13otherwise satisfy the criteria of this Section or Section 
148-406.1 and the criteria of Section 8-503, as applicable to 
15the application and to the extent such criteria are not 
16superseded by the provisions of this subsection. The 
17Commission's order on the application for the certificate of 
18public convenience and necessity shall also include the 
19Commission's findings and determinations on the request or 
20requests for authority pursuant to Section 8-503. Prior to 
21filing its application under either this Section or Section 
228-406.1, the qualifying direct current applicant shall conduct 
233 public meetings in accordance with subsection (h) of this 
24Section. If the qualifying direct current applicant 
25demonstrates in its application that the proposed qualifying 
26direct current project is designed to deliver electricity to a 
 
 
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1point or points on the electric transmission grid in either or 
2both the PJM Interconnection, LLC or the Midcontinent 
3Independent System Operator, Inc., or their respective 
4successor organizations, the proposed qualifying direct 
5current project shall be deemed to be, and the Commission 
6shall find it to be, for public use. If the qualifying direct 
7current applicant further demonstrates in its application that 
8the proposed transmission project has a capacity of 1,000 
9megawatts or larger and a voltage level of 345 kilovolts or 
10greater, the proposed transmission project shall be deemed to 
11satisfy, and the Commission shall find that it satisfies, the 
12criteria stated in item (1) of subsection (b) of this Section 
13or in paragraph (1) of subsection (f) of Section 8-406.1, as 
14applicable to the application, without the taking of 
15additional evidence on these criteria. Prior to the transfer 
16of functional control of any transmission assets to a regional 
17transmission organization, a qualifying direct current 
18applicant shall request Commission approval to join a regional 
19transmission organization in an application filed pursuant to 
20this subsection (b-5) or separately pursuant to Section 7-102 
21of this Act. The Commission may grant permission to a 
22qualifying direct current applicant to join a regional 
23transmission organization if it finds that the membership, and 
24associated transfer of functional control of transmission 
25assets, benefits Illinois customers in light of the attendant 
26costs and is otherwise in the public interest. Nothing in this 
 
 
10400SB0025ham002- 534 -LRB104 07069 AAS 28576 a

1subsection (b-5) requires a qualifying direct current 
2applicant to join a regional transmission organization. 
3Nothing in this subsection (b-5) requires the owner or 
4operator of a high voltage direct current transmission line 
5that is not a qualifying direct current project to obtain a 
6certificate of public convenience and necessity to the extent 
7it is not otherwise required by this Section 8-406 or any other 
8provision of this Act. 
9    (c) As used in this subsection (c):
10    "Decommissioning" has the meaning given to that term in 
11subsection (a) of Section 8-508.1.
12    "Nuclear power reactor" has the meaning given to that term 
13in Section 8 of the Nuclear Safety Law of 2004. 
14    After the effective date of this amendatory Act of the 
15103rd General Assembly, no construction shall commence on any 
16new nuclear power reactor with a nameplate capacity of more 
17than 300 megawatts of electricity to be located within this 
18State, and no certificate of public convenience and necessity 
19or other authorization shall be issued therefor by the 
20Commission, until the Illinois Emergency Management Agency and 
21Office of Homeland Security, in consultation with the Illinois 
22Environmental Protection Agency and the Illinois Department of 
23Natural Resources, finds that the United States Government, 
24through its authorized agency, has identified and approved a 
25demonstrable technology or means for the disposal of high 
26level nuclear waste, or until such construction has been 
 
 
10400SB0025ham002- 535 -LRB104 07069 AAS 28576 a

1specifically approved by a statute enacted by the General 
2Assembly. Beginning January 1, 2026, construction may commence 
3on a new nuclear power reactor with a nameplate capacity of 300 
4megawatts of electricity or less within this State if the 
5entity constructing the new nuclear power reactor has obtained 
6all permits, licenses, permissions, or approvals governing the 
7construction, operation, and funding of decommissioning of 
8such nuclear power reactors required by: (1) this Act; (2) any 
9rules adopted by the Illinois Emergency Management Agency and 
10Office of Homeland Security under the authority of this Act; 
11(3) any applicable federal statutes, including, but not 
12limited to, the Atomic Energy Act of 1954, the Energy 
13Reorganization Act of 1974, the Low-Level Radioactive Waste 
14Policy Amendments Act of 1985, and the Energy Policy Act of 
151992; (4) any regulations promulgated or enforced by the U.S. 
16Nuclear Regulatory Commission, including, but not limited to, 
17those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of 
18the Code of Federal Regulations, as from time to time amended; 
19and (5) any other federal or State statute, rule, or 
20regulation governing the permitting, licensing, operation, or 
21decommissioning of such nuclear power reactors. None of the 
22rules developed by the Illinois Emergency Management Agency 
23and Office of Homeland Security or any other State agency, 
24board, or commission pursuant to this Act shall be construed 
25to supersede the authority of the U.S. Nuclear Regulatory 
26Commission. The changes made by this amendatory Act of the 
 
 
10400SB0025ham002- 536 -LRB104 07069 AAS 28576 a

1103rd General Assembly shall not apply to the uprate, renewal, 
2or subsequent renewal of any license for an existing nuclear 
3power reactor that began operation prior to the effective date 
4of this amendatory Act of the 103rd General Assembly. 
5    None of the changes made in this amendatory Act of the 
6103rd General Assembly are intended to authorize the 
7construction of nuclear power plants powered by nuclear power 
8reactors that are not either: (1) small modular nuclear 
9reactors; or (2) nuclear power reactors licensed by the U.S. 
10Nuclear Regulatory Commission to operate in this State prior 
11to the effective date of this amendatory Act of the 103rd 
12General Assembly. 
13    (d) In making its determination under subsection (b) of 
14this Section, the Commission shall attach primary weight to 
15the cost or cost savings to the customers of the utility. The 
16Commission may consider any or all factors which will or may 
17affect such cost or cost savings, including the public 
18utility's engineering judgment regarding the materials used 
19for construction.
20    (e) The Commission may issue a temporary certificate which 
21shall remain in force not to exceed one year in cases of 
22emergency, to assure maintenance of adequate service or to 
23serve particular customers, without notice or hearing, pending 
24the determination of an application for a certificate, and may 
25by regulation exempt from the requirements of this Section 
26temporary acts or operations for which the issuance of a 
 
 
10400SB0025ham002- 537 -LRB104 07069 AAS 28576 a

1certificate will not be required in the public interest.
2    A public utility shall not be required to obtain but may 
3apply for and obtain a certificate of public convenience and 
4necessity pursuant to this Section with respect to any matter 
5as to which it has received the authorization or order of the 
6Commission under the Electric Supplier Act, and any such 
7authorization or order granted a public utility by the 
8Commission under that Act shall as between public utilities be 
9deemed to be, and shall have except as provided in that Act the 
10same force and effect as, a certificate of public convenience 
11and necessity issued pursuant to this Section.
12    No electric cooperative shall be made or shall become a 
13party to or shall be entitled to be heard or to otherwise 
14appear or participate in any proceeding initiated under this 
15Section for authorization of power plant construction and as 
16to matters as to which a remedy is available under the Electric 
17Supplier Act.
18    (f) Such certificates may be altered or modified by the 
19Commission, upon its own motion or upon application by the 
20person or corporation affected. Unless exercised within a 
21period of 2 years from the grant thereof, authority conferred 
22by a certificate of convenience and necessity issued by the 
23Commission shall be null and void.
24    No certificate of public convenience and necessity shall 
25be construed as granting a monopoly or an exclusive privilege, 
26immunity or franchise.
 
 
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1    (g) A public utility that undertakes any of the actions 
2described in items (1) through (3) of this subsection (g) or 
3that has obtained approval pursuant to Section 8-406.1 of this 
4Act shall not be required to comply with the requirements of 
5this Section to the extent such requirements otherwise would 
6apply. For purposes of this Section and Section 8-406.1 of 
7this Act, "high voltage electric service line" means an 
8electric line having a design voltage of 100,000 or more. For 
9purposes of this subsection (g), a public utility may do any of 
10the following:
11        (1) replace or upgrade any existing high voltage 
12    electric service line and related facilities, 
13    notwithstanding its length;
14        (2) relocate any existing high voltage electric 
15    service line and related facilities, notwithstanding its 
16    length, to accommodate construction or expansion of a 
17    roadway or other transportation infrastructure; or
18        (3) construct a high voltage electric service line and 
19    related facilities that is constructed solely to serve a 
20    single customer's premises or to provide a generator 
21    interconnection to the public utility's transmission 
22    system and that will pass under or over the premises owned 
23    by the customer or generator to be served or under or over 
24    premises for which the customer or generator has secured 
25    the necessary right-of-way right of way. 
26    (h) A public utility seeking to construct a high-voltage 
 
 
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1electric service line and related facilities (Project) must 
2show that the utility has held a minimum of 2 pre-filing public 
3meetings to receive public comment concerning the Project in 
4each county where the Project is to be located, no earlier than 
56 months prior to filing an application for a certificate of 
6public convenience and necessity from the Commission. Notice 
7of the public meeting shall be published in a newspaper of 
8general circulation within the affected county once a week for 
93 consecutive weeks, beginning no earlier than one month prior 
10to the first public meeting. If the Project traverses 2 
11contiguous counties and where in one county the transmission 
12line mileage and number of landowners over whose property the 
13proposed route traverses is one-fifth or less of the 
14transmission line mileage and number of such landowners of the 
15other county, then the utility may combine the 2 pre-filing 
16meetings in the county with the greater transmission line 
17mileage and affected landowners. All other requirements 
18regarding pre-filing meetings shall apply in both counties. 
19Notice of the public meeting, including a description of the 
20Project, must be provided in writing to the clerk of each 
21county where the Project is to be located. A representative of 
22the Commission shall be invited to each pre-filing public 
23meeting.
24    (h-5) A public utility seeking to construct a high-voltage 
25electric service line and related facilities must also show 
26that the Project has complied with training and competence 
 
 
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1requirements under subsection (b) of Section 15 of the 
2Electric Transmission Systems Construction Standards Act. 
3    (i) For applications filed after August 18, 2015 (the 
4effective date of Public Act 99-399), the Commission shall, by 
5certified mail, notify each owner of record of land, as 
6identified in the records of the relevant county tax assessor, 
7included in the right-of-way over which the utility seeks in 
8its application to construct a high-voltage electric line of 
9the time and place scheduled for the initial hearing on the 
10public utility's application. The utility shall reimburse the 
11Commission for the cost of the postage and supplies incurred 
12for mailing the notice.
13(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21; 
14102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff. 
156-1-24; 103-1066, eff. 2-20-25.)
 
16    (220 ILCS 5/8-512)
17    Sec. 8-512. Renewable energy access plan.
18    (a) It is the policy of this State to promote 
19cost-effective transmission system development that ensures 
20reliability of the electric transmission system, lowers carbon 
21emissions, minimizes long-term costs for consumers, and 
22supports the electric policy goals of this State. The General 
23Assembly finds that:
24        (1) Transmission planning, primarily for reliability 
25    purposes, but also for economic and public policy reasons 
 
 
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1    is conducted by regional transmission organizations in 
2    which transmission-owning Illinois utilities and other 
3    stakeholders are members.
4        (2) Order No. 1000 of the Federal Energy Regulatory 
5    Commission requires regional transmission organizations to 
6    plan for transmission system needs in light of State 
7    public policies and to accept input from states during the 
8    transmission system planning processes.
9        (3) The State of Illinois does not currently have a 
10    comprehensive power and environmental policy planning 
11    process to identify transmission infrastructure needs that 
12    can serve as a vital input into the regional and 
13    interregional transmission organization planning 
14    processes conducted under Order No. 1000 and other laws 
15    and regulations.
16        (4) This State is an electricity generation and power 
17    transmission hub, and can leverage that position to invest 
18    in infrastructure that enables new and existing Illinois 
19    generators to meet the public policy goals of the State of 
20    Illinois and of interconnected states while 
21    cost-effectively supporting tens of thousands of jobs in 
22    the renewable energy sector in this State.
23        (5) The nation has a need to readily access this 
24    State's low-cost, clean electric power, and this State 
25    also desires access to clean energy resources in other 
26    states to develop and support its low-carbon economy and 
 
 
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1    keep electricity prices low in Illinois and interconnected 
2    States.
3        (6) Existing transmission infrastructure may constrain 
4    the State's achievement of 100% renewable energy by 2050, 
5    the accelerated adoption of electric vehicles in a just 
6    and equitable way, and electrification of additional 
7    sectors of the Illinois economy.
8        (7) Transmission system congestion within this State 
9    and the regional transmission organizations serving this 
10    State limits the ability of this State's existing and new 
11    electric generation facilities that do not emit carbon 
12    dioxide, including renewable energy resources and zero 
13    emission facilities, to serve the public policy goals of 
14    this State and other states, which constrains investment 
15    in this State.
16        (8) Investment in infrastructure to support existing 
17    and new electric generation facilities that do not emit 
18    carbon dioxide, including renewable energy resources and 
19    zero emission facilities, stimulates significant economic 
20    development and job growth in this State, as well as 
21    creates environmental and public health benefits in this 
22    State.
23        (9) Creating a forward-looking plan for this State's 
24    electric transmission infrastructure, as opposed to 
25    relying on case-by-case development and repeated marginal 
26    upgrades, will achieve a lower-cost system for Illinois' 
 
 
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1    electricity customers. A forward-looking plan can also 
2    help integrate and achieve a comprehensive set of 
3    objectives and multiple state, regional, and national 
4    policy goals.
5        (10) Alternatives to overhead electric transmission 
6    lines can achieve cost-effective resolution of system 
7    impacts and warrant investigation of the circumstances 
8    under which those alternatives should be considered and 
9    approved. The alternatives are likely to be beneficial as 
10    investment in electric transmission infrastructure moves 
11    forward.
12        (11) Because transmission planning is conducted 
13    primarily by the regional transmission organizations, the 
14    Commission should be advocating for the State's interests 
15    at the regional transmission organizations to ensure that 
16    such planning facilitates the State's policies and goals, 
17    including overall consumer savings, power system 
18    reliability, economic development, environmental 
19    improvement, and carbon reduction.
20        (12) Advanced transmission technologies have an 
21    important role to play in meeting the State's clean energy 
22    goals. For the purposes of this Section, "advanced 
23    transmission technology" is hardware or software that 
24    provides cost-effective increases to the capacity, 
25    efficiency, or reliability of existing transmission 
26    infrastructure, and includes, but is not limited to: (i) 
 
 
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1    technology that dynamically adjusts the rated capacity of 
2    transmission lines based on real-time conditions; (ii) 
3    advanced power flow controls used to actively control the 
4    flow of electricity across transmission lines to optimize 
5    usage or relieve congestion; (iii) software or hardware 
6    used to identify optimal transmission grid configurations 
7    or enable routing power flows around congestion points; 
8    and (iv) advanced transmission line conductors that have a 
9    direct current electrical resistance at least 10% lower 
10    than existing conductors of a similar diameter on the 
11    transmission system.    
12    (b) Consistent with the findings identified in subsection 
13(a), the Commission shall open an investigation to develop and 
14adopt an initial a renewable energy access plan no later than 
15December 31, 2022. To assist and support the Commission in the 
16development of the plan, the Commission shall retain the 
17services of technical and policy experts with relevant fields 
18of expertise, solicit technical and policy analysis from the 
19public, and provide for a 120-day open public comment period 
20after publication of a draft report, which shall be published 
21no later than 90 days after the comment period ends. The plan 
22shall, at a minimum, do the following:
23        (1) designate renewable energy access plan zones 
24    throughout this State in areas in which renewable energy 
25    resources and suitable land areas are sufficient for 
26    developing generating capacity from renewable energy 
 
 
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1    technologies;
2        (2) develop a plan to achieve transmission capacity 
3    necessary to deliver the electric output from renewable 
4    energy technologies in the renewable energy access plan 
5    zones to customers in Illinois and other states in a 
6    manner that is most beneficial and cost-effective to 
7    customers;
8        (3) use this State's position as an electricity 
9    generation and power transmission hub to create new 
10    investment in this State's renewable energy resources;
11        (4) consider programs, policies, and electric 
12    transmission projects that can be adopted within this 
13    State that promote the cost-effective delivery of power 
14    from renewable energy resources interconnected to the bulk 
15    electric system to meet the renewable portfolio standard 
16    targets under subsection (c) of Section 1-75 of the 
17    Illinois Power Agency Act;
18        (5) consider proposals to improve regional 
19    transmission organizations' regional and interregional 
20    system planning processes, especially proposals that 
21    reduce costs and emissions, create jobs, and increase 
22    State and regional power system reliability to prevent 
23    high-cost outages that can endanger lives, and analyze of 
24    how those proposals would improve reliability and 
25    cost-effective delivery of electricity in Illinois and the 
26    region;
 
 
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1        (6) make findings and policy recommendations based on 
2    technical and policy analysis regarding locations of 
3    renewable energy access plan zones and the transmission 
4    system developments needed to cost-effectively achieve the 
5    public policy goals identified herein;
6        (6.5) make findings and policy recommendations based 
7    on analysis regarding the impact of converting non-powered 
8    dams to hydropower dams relative to the alternative 
9    renewable energy resources; and 
10        (7) present the Commission's conclusions and proposed 
11    recommendations based on its analysis and use the findings 
12    and policy recommendations to determine actions that the 
13    Commission should take.
14    (c) No later than December 31, 2025 or 180 days after the 
15effective date of this amendatory Act of the 104th General 
16Assembly, whichever is later, and every other year thereafter, 
17the Commission shall open an investigation to develop and 
18adopt a an updated renewable energy access plan update that 
19considers electric transmission projects, transmission 
20policies, transmission alternatives, advanced transmission 
21technologies, other ways to expand capacity on existing or 
22future transmission, and transmission headroom and, at a 
23minimum, : evaluates the implementation and effectiveness of 
24the renewable energy access plan, recommends improvements to 
25the renewable energy access plan, and provides changes to 
26transmission capacity necessary to deliver electric output 
 
 
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1from the renewable energy access plan zones.
2        (1) evaluates the implementation and effectiveness of 
3    the renewable energy access plan;
4        (2) recommends improvements to the renewable energy 
5    access plan;
6        (3) includes updated inputs and assumptions developed 
7    under the integrated resource plan developed and approved 
8    pursuant to Section 16-201 and Section 16-202;
9        (4) requests utilities and other parties to 
10    specifically identify all elements of the existing 
11    transmission system where advanced transmission 
12    technologies are likely to achieve enhanced system 
13    resilience or reliability, reduce potential siting 
14    conflicts or land impacts from the development of new 
15    transmission lines, promote the cost-effective delivery of 
16    power from renewable energy resources interconnected to 
17    the bulk electric system, enable the interconnection of 
18    renewable energy resources, or reduce curtailment of 
19    renewable energy resources. The plan must identify all 
20    elements of the existing transmission system which have 
21    experienced capacity constraints or congestion within the 
22    prior 2 years and explain whether any advanced 
23    transmission technology could reduce or resolve the 
24    capacity constraint or congestion;
25        (5) includes an evaluation of identified and proposed 
26    transmission projects, including proposed advanced 
 
 
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1    transmission technology projects, based on independent 
2    analysis of costs and benefits, including customer bill 
3    impacts over the life of the project and achievement of 
4    State clean energy goals. Projects shall be evaluated in 
5    coordination with other proposals, and may include a 
6    combined evaluation of portfolios of projects;
7        (6) develops a recommended list of transmission 
8    projects and advanced transmission technology projects 
9    that achieve the clean energy public policy objectives of 
10    the State. Nothing in this Section shall limit the 
11    recommended list of transmission projects to those 
12    initially proposed. However, no transmission or advanced 
13    transmission technology project can be included in the 
14    recommended list unless evaluated; and
15        (7) considers additional mechanisms designed to 
16    capture the potential value of geographically diverse 
17    resources that proposed interregional transmission 
18    projects may provide.    
19    The Commission may evaluate options for implementation of 
20the recommended list of transmission projects and advanced 
21transmission technology projects that achieve the clean energy 
22public policy objectives of the State, including through the 
23use of a state agreement approach or a similar structure made 
24available through the relevant regional transmission 
25organizations, and approves final recommendations on 
26implementation.
 
 
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1    The Commission may invite parties to identify transmission 
2projects, including any associated network upgrades, necessary 
3to facilitate achievement of the goals of the plan and the most 
4recently approved integrated resource plan. Proposals for 
5projects shall include a description of each project; a 
6proposed target date for completion; an estimated timeline for 
7development; the energy, capacity, and generation profile of 
8renewable generation and energy storage enabled by the 
9project; anticipated new loads served by the project; the 
10proposed technology used, including the use of any advanced 
11transmission technologies; and the status of any permits or 
12approvals necessary. For projects with a target completion 
13date of within 5 years from the date of proposal, the proposal 
14must also include an estimated cost of the project and the 
15proposed routing corridor. The Commission shall aim to 
16complete the updated plan investigation within 12 months of 
17opening.
18    (d) Each transmission-owning State utility serving more 
19than 200,000 customers in this State may prepare a plan for 
20integrating advanced transmission technologies into the 
21utility's existing transmission system. The plan must identify 
22all elements of the existing transmission system where 
23advanced transmission technologies are likely to achieve any 
24of the following purposes:
25        (1) enhance system resilience or reliability;
26        (2) reduce potential siting conflicts or land impacts 
 
 
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1    from the development of new transmission lines;
2        (3) promote the cost-effective delivery of power from 
3    renewable energy resources interconnected to the bulk 
4    electric system to meet the renewable portfolio standard 
5    targets under subsection (c) of Section 1-75 of the 
6    Illinois Power Agency Act;
7        (4) enable the interconnection of renewable energy 
8    resources to meet the renewable portfolio standard targets 
9    under subsection (c) of Section 1-75 of the Illinois Power 
10    Agency Act; or
11        (5) reduce curtailment of renewable or zero-carbon 
12    resources.
13    The plan must identify all elements of the existing 
14transmission system which have experienced capacity 
15constraints or congestion within the prior 2 years and explain 
16whether any advanced transmission technology could reduce or 
17resolve the capacity constraint or congestion. Each 
18transmission-owning State utility may submit an advanced 
19transmission technology integration plan to the Commission for 
20consideration as part of the Commission's updated renewable 
21energy access plan investigation under subsection (c). In the 
22Commission's updated renewable energy access plan, the 
23Commission may evaluate, request modifications for, change the 
24timelines of implementation for, and determine the next steps 
25for each advanced transmission integration plan.
26    (e) Each transmission-owning State utility serving more 
 
 
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1than 200,000 customers in this State may conduct a 
2comprehensive Transmission Headroom Study that shall identify, 
3at a minimum, the points of interconnection with unused, 
4existing transmission headroom on the State system, including 
5available capacity behind existing, underutilized points of 
6interconnection, and the amount of available headroom in 
7megawatts at each identified point of interconnection. Each 
8transmission-owning State utility may submit a Transmission 
9Headroom Study to the Commission for consideration as part of 
10the Commission's updated renewable energy access plan 
11investigation under subsection (c).
12    (f) The Commission shall approve an updated renewable 
13energy access plan if it finds that, at a minimum, the evidence 
14in the investigation meets the criteria outlined in subsection 
15(c) and demonstrates that the updated plan will support the 
16clean energy public policy objectives of the State.    
17    (g) The Commission shall notify the applicable regional 
18transmission organizations and utilities of any final 
19recommendations to support the clean energy public policy 
20objectives of the State.
21    (h) Nothing in this Section alters the rights of 
22transmission utilities (i) under rates on file with the 
23Federal Energy Regulatory Commission or the Illinois Commerce 
24Commission, (ii) under orders and determinations of the 
25Federal Energy Regulatory Commission or a regional 
26transmission organization, or (iii) under applicable State 
 
 
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1laws and policies.
2(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
 
3    (220 ILCS 5/8-513 new)
4    Sec. 8-513. Thermal Energy Network Pilot Program.
5    (a) The Commission shall coordinate with the Illinois 
6Finance Authority, in its role as Climate Bank for the State, 
7to leverage any available federal funding to support thermal 
8energy network pilot projects through the provision of grants 
9or to provide or leverage financing. If that federal funding 
10is not available or not sufficient to meet program objectives, 
11the Commission shall authorize the allocation of up to 
12$20,000,000 to support the thermal energy network pilot 
13projects, to be provided to the Illinois Finance Authority to 
14distribute to projects as a grant or to provide or leverage 
15financing. The Illinois Finance Authority shall submit 
16projects that have already been approved by the Illinois 
17Finance Authority to the Commission for review and approval in 
18a form and manner determined by the Commission. The Commission 
19shall approve projects that it deems to be just, reasonable, 
20and in the public interest. Any allocation of funding shall 
21provide for the Illinois Finance Authority to use a portion of 
22such allocated funds to support its reasonable administrative 
23costs in administering the program under this Section.
24    (b) An electric utility shall be entitled to recover, 
25through tariffed charges approved by the Commission, all of 
 
 
10400SB0025ham002- 553 -LRB104 07069 AAS 28576 a

1the costs associated with projects authorized for funding by 
2the Commission pursuant to this Section and shall be recovered 
3as part of the utility's costs incurred under Section 45 of the 
4Electric Vehicle Act. If any authorized funds have not been 
5recovered by the utility as of January 1, 2029, the 
6Environmental Protection Agency shall allocate the remaining 
7funds to the Illinois Finance Authority as part of its 
8beneficial electrification programs described in Section 45 of 
9the Electric Vehicle Act.    
10    (c) As part of any pilot project proposed pursuant to this 
11Section, the Commission is authorized to approve any specific 
12customer rebates and incentives and any project-specific 
13tariffs and rules. The Commission may create a standard 
14proposed rate structure or minimum requirements for a rate 
15structure to be required of all thermal energy network pilot 
16projects. The Commission may approve the proposed rate 
17structure of a thermal energy network pilot project if the 
18projected heating and cooling costs for end users is not 
19greater than the projected heating and cooling costs the end 
20users would have incurred if the end users had not 
21participated in the program. In its approval process, the 
22Commission shall take into account scenarios where pilot 
23projects enhance comfort and safety for customers through 
24expanded access to affordable heating and cooling.
25    (d) Approved thermal energy network pilot projects shall 
26report to the Commission, on a quarterly basis and until 
 
 
10400SB0025ham002- 554 -LRB104 07069 AAS 28576 a

1completion of the thermal energy network pilot project, the 
2status of each thermal energy network pilot project. The 
3Commission shall post and make publicly available the reports 
4on its website. The reports shall include, but not be limited 
5to:
6        (1) the stage of development of each pilot project;
7        (2) the barriers to development;
8        (3) the number of customers served;
9        (4) the costs of the pilot project;
10        (5) the number of jobs retained or created by the 
11    pilot project;
12        (6) energy savings and fuel savings from the project 
13    and energy consumption by the project; and
14        (7) other information the Commission deems to be in 
15    the public interest or considers likely to prove useful or 
16    relevant to the rulemaking described in subsection (i).
17    (e) Any entity operating a Commission-approved thermal 
18energy network pilot project shall demonstrate that it has 
19entered into a labor peace agreement with a bona fide labor 
20organization that is actively engaged in representing its 
21employees. The labor peace agreement shall apply to the 
22employees necessary for the ongoing maintenance and operation 
23of the thermal energy network. The existence of a labor peace 
24agreement shall be an ongoing material condition of an 
25entity's authorization to maintain and operate the thermal 
26energy networks.
 
 
10400SB0025ham002- 555 -LRB104 07069 AAS 28576 a

1    (f) Any contractor or subcontractor that performs work on 
2a thermal energy network pilot project under this Section 
3shall be a responsible bidder, as described in Section 30-22 
4of the Illinois Procurement Code, and shall certify that not 
5less than prevailing wage, as determined under the Prevailing 
6Wage Act, was or will be paid to the employees who are engaged 
7in construction activities associated with the pilot thermal 
8energy network system. The contractor or subcontractor shall 
9submit evidence to the Commission that it complied with the 
10requirements of this subsection (f). For any approved thermal 
11energy network pilot project, the contractor or subcontractor 
12shall submit evidence that the contractor or subcontractor has 
13entered into a fully executed project labor agreement for the 
14thermal energy network system prior to the initiation of 
15construction activities.
 
16    (220 ILCS 5/9-229)
17    Sec. 9-229. Consideration of attorney and expert 
18compensation as an expense and intervenor compensation fund. 
19    (a) The Commission shall specifically assess the justness 
20and reasonableness of any amount expended by a public utility 
21to compensate attorneys or technical experts to prepare and 
22litigate a general rate case filing. This issue shall be 
23expressly addressed in the Commission's final order.
24    (b) The State of Illinois shall create a Consumer 
25Intervenor Compensation Fund subject to the following:
 
 
10400SB0025ham002- 556 -LRB104 07069 AAS 28576 a

1        (1) Provision of compensation for consumer interest 
2    representatives Consumer Interest Representatives that 
3    intervene in Illinois Commerce Commission proceedings will 
4    increase public engagement, encourage additional 
5    transparency, expand the information available to the 
6    Commission, and improve decision-making.
7        (2) As used in this Section, "consumer Consumer    
8    interest representative" means:
9            (A) a residential utility customer or group of 
10        residential utility customers represented by a 
11        not-for-profit group or organization registered with 
12        the Illinois Attorney General under the Solicitation 
13        for Charity Act;
14            (B) representatives of not-for-profit groups or 
15        organizations whose membership is limited to 
16        residential utility customers; or
17            (C) representatives of not-for-profit groups or 
18        organizations whose membership includes Illinois 
19        residents and that address the community, economic, 
20        environmental, or social welfare of Illinois 
21        residents, except government agencies or intervenors    
22        specifically authorized by Illinois law to participate 
23        in Commission proceedings on behalf of Illinois 
24        consumers.
25        (3) A consumer interest representative is eligible to 
26    receive compensation from the Consumer Intervenor 
 
 
10400SB0025ham002- 557 -LRB104 07069 AAS 28576 a

1    Compensation Fund consumer intervenor compensation fund if 
2    its participation included lay or expert testimony or 
3    legal briefing and argument concerning the expenses, 
4    investments, rate design, rate impact, development of an 
5    integrated resource plan pursuant to Section 16-201 and 
6    any related proceedings, or other matters affecting the 
7    pricing, rates, costs or other charges associated with 
8    utility service and , the Commission does not find the 
9    participation to be immaterial adopts a material 
10    recommendation related to a significant issue in the 
11    docket, and participation caused a significant financial 
12    hardship to the participant; however, no consumer interest 
13    representative shall be eligible to receive an award 
14    pursuant to this Section if the consumer interest 
15    representative receives any compensation, funding, or 
16    donations, directly or indirectly, from parties that have 
17    a financial interest in the outcome of the proceeding. 
18    Funding from residential ratepayers shall not be 
19    considered funding from a party with a financial interest 
20    unless determined to be by the Commission. The Commission 
21    shall determine participation by the consumer interest 
22    representative to be material if recommendations made by 
23    the consumer interest representative are:
24            (A) relevant to issues in the proceeding on which 
25        the Commission makes a finding;
26            (B) supported by facts, such as studies, methods, 
 
 
10400SB0025ham002- 558 -LRB104 07069 AAS 28576 a

1        or calculations, or by legal or policy analysis; and
2            (C) offered by the consumer interest 
3        representative into evidence in the record of that 
4        proceeding, or for legal or policy analysis, are filed 
5        in the docket of that proceeding, through briefing, 
6        motion, or other method.    
7        (4) Within 30 days after September 15, 2021 (the 
8    effective date of Public Act 102-662), each utility that 
9    files a request for an increase in rates under Article IX 
10    or Article XVI shall deposit an amount equal to one half of 
11    the rate case attorney and expert expense allowed by the 
12    Commission, but not to exceed $500,000, into the fund 
13    within 35 days of the date of the Commission's final Order 
14    in the rate case or 20 days after the denial of rehearing 
15    under Section 10-113 of this Act, whichever is later. The 
16    Consumer Intervenor Compensation Fund shall be used to 
17    provide payment to consumer interest representatives as 
18    described in this Section.
19        (5) An electric public utility with 3,000,000 or more 
20    retail customers shall contribute $450,000 to the Consumer 
21    Intervenor Compensation Fund within 60 days after 
22    September 15, 2021 (the effective date of Public Act 
23    102-662). A combined electric and gas public utility 
24    serving fewer than 3,000,000 but more than 500,000 retail 
25    customers shall contribute $225,000 to the Consumer 
26    Intervenor Compensation Fund within 60 days after 
 
 
10400SB0025ham002- 559 -LRB104 07069 AAS 28576 a

1    September 15, 2021 (the effective date of Public Act 
2    102-662). A gas public utility with 1,500,000 or more 
3    retail customers that is not a combined electric and gas 
4    public utility shall contribute $225,000 to the Consumer 
5    Intervenor Compensation Fund within 60 days after 
6    September 15, 2021 (the effective date of Public Act 
7    102-662). A gas public utility with fewer than 1,500,000 
8    retail customers but more than 300,000 retail customers 
9    that is not a combined electric and gas public utility 
10    shall contribute $80,000 to the Consumer Intervenor 
11    Compensation Fund within 60 days after September 15, 2021 
12    (the effective date of Public Act 102-662). A gas public 
13    utility with fewer than 300,000 retail customers that is 
14    not a combined electric and gas public utility shall 
15    contribute $20,000 to the Consumer Intervenor Compensation 
16    Fund within 60 days after September 15, 2021 (the 
17    effective date of Public Act 102-662). A combined electric 
18    and gas public utility serving fewer than 500,000 retail 
19    customers shall contribute $20,000 to the Consumer 
20    Intervenor Compensation Fund within 60 days after 
21    September 15, 2021 (the effective date of Public Act 
22    102-662). A water or sewer public utility serving more 
23    than 100,000 retail customers shall contribute $80,000, 
24    and a water or sewer public utility serving fewer than 
25    100,000 but more than 10,000 retail customers shall 
26    contribute $20,000.
 
 
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1        (6)(A) Prior to the entry of a final order Final Order    
2    in a docketed case, the Commission Administrator shall 
3    provide a payment to a consumer interest representative 
4    that demonstrates through a verified application for 
5    funding that the consumer interest representative's 
6    participation or intervention without an award of fees or 
7    costs imposes a significant financial cost for the 
8    consumer interest representative hardship based on a 
9    schedule to be developed by the Commission. The 
10    Administrator may require verification of costs expected 
11    to be incurred, including statements of expected hours 
12    spent, as a condition to paying the consumer interest 
13    representative prior to the entry of a final order Final 
14    Order in a docketed case. The upfront payment prior to the 
15    entry of a final order in the relevant docketed case shall 
16    be subject to the reconciliation process described in 
17    subparagraph (C) of this paragraph. For purposes of 
18    upfront payments provided for under this subparagraph, and 
19    provided the testimony or legal argument was offered into 
20    evidence or filed in the docket, a decision by the 
21    Commission prior to entry of a final order that a consumer 
22    interest representative's evidence or legal argument is 
23    relevant to issues in the proceeding under subparagraph 
24    (A) of paragraph (3) shall not be subject to 
25    reconsideration. Any compensation awarded shall be subject 
26    to review and reconciliation under subparagraph (C) of 
 
 
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1    this paragraph. Payments made after the issuance of a 
2    final order in the relevant docketed case do not require 
3    the reconciliation.    
4        (B) If the Commission does not find the participation 
5    to be immaterial adopts a material recommendation related 
6    to a significant issue in the docket and participation 
7    caused a financial hardship to the participant, then the 
8    consumer interest representative shall be allowed payment 
9    for some or all of the consumer interest representative's 
10    reasonable attorney's or advocate's fees, reasonable 
11    expert witness fees, and other reasonable costs of 
12    preparation for and participation in a hearing or 
13    proceeding. Expenses related to travel or meals shall not 
14    be compensable. Expenses incurred by participation in 
15    workshops or other informal processes outside a docketed 
16    proceeding shall not be compensable. Attorneys and expert 
17    witnesses who represent or testify for more than one party 
18    in the same docketed proceeding and perform essentially 
19    the same work on behalf of the parties shall not be 
20    compensated more than once for those same services 
21    rendered in that proceeding.    
22        (C) The consumer interest representative shall submit 
23    an itemized request for compensation to the Consumer 
24    Intervenor Compensation Fund, including the advocate's or 
25    attorney's reasonable fee rate, the number of hours 
26    expended, reasonable expert and expert witness fees, and 
 
 
10400SB0025ham002- 562 -LRB104 07069 AAS 28576 a

1    other reasonable costs for the preparation for and 
2    participation in the hearing and briefing within 30 days 
3    after of the Commission's final order or the Commission's    
4    after denial or decision on rehearing, if any, whichever 
5    is later. If compensation is provided prior to the entry 
6    of a final order in a docketed case, such compensation 
7    shall be adjusted following the final order to reconcile 
8    the difference between actual eligible expenses incurred 
9    and the amount of compensation provided prior to the entry 
10    of the final order. The reconciliation adjustment shall 
11    ensure that the total compensation awarded to the 
12    applicant is no more and no less than the actual eligible 
13    expenses incurred. Payments made after the issuance of a 
14    final order in the relevant docketed case do not require 
15    the reconciliation.    
16        (7) Administration of the Fund.
17        (A) The Consumer Intervenor Compensation Fund is 
18    created as a special fund in the State treasury. All 
19    disbursements from the Consumer Intervenor Compensation 
20    Fund shall be made only upon warrants of the Comptroller 
21    drawn upon the Treasurer as custodian of the Fund upon 
22    vouchers signed by the Executive Director of the 
23    Commission or by the person or persons designated by the 
24    Director for that purpose. The Comptroller is authorized 
25    to draw the warrant upon vouchers so signed. The Treasurer 
26    shall accept all warrants so signed and shall be released 
 
 
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1    from liability for all payments made on those warrants. 
2    The Consumer Intervenor Compensation Fund shall be 
3    administered by an Administrator that is a person or 
4    entity that is independent of the Commission. The 
5    administrator will be responsible for the prudent 
6    management of the Consumer Intervenor Compensation Fund 
7    and for recommendations for the award of consumer 
8    intervenor compensation from the Consumer Intervenor 
9    Compensation Fund. The Commission shall issue a request 
10    for qualifications for a third-party program administrator 
11    to administer the Consumer Intervenor Compensation Fund. 
12    The third-party administrator shall be chosen through a 
13    competitive bid process based on selection criteria and 
14    requirements developed by the Commission. The Illinois 
15    Procurement Code does not apply to the hiring or payment 
16    of the Administrator. All Administrator costs may be paid 
17    for using monies from the Consumer Intervenor Compensation 
18    Fund, but the Program Administrator shall strive to 
19    minimize costs in the implementation of the program.
20        (B) The computation of compensation awarded from the 
21    fund shall take into consideration the market rates paid 
22    to persons of comparable training and experience who offer 
23    similar services, but may not exceed the comparable market 
24    rate for services paid by the public utility as part of its 
25    rate case expense.
26        (C)(1) Recommendations on the award of compensation by 
 
 
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1    the administrator shall include consideration of whether 
2    the participation was material Commission adopted a 
3    material recommendation related to a significant issue in 
4    the docket and whether participation caused a financial 
5    hardship to the participant and the payment of 
6    compensation is fair, just and reasonable.
7        (2) Recommendations on the award of compensation by 
8    the administrator shall be submitted to the Commission for 
9    approval within 30 days after when the application for 
10    funding is submitted to the administrator. Unless the 
11    Commission initiates an investigation within 60 45 days 
12    after an application for funding is submitted to the 
13    administrator, the Commission shall within 90 days after 
14    the application is submitted to the administrator, or as 
15    soon as practicable thereafter, award funding to the 
16    applicant. Notice of the administrator's award 
17    recommendation the notice to the Commission, the award of 
18    compensation shall be allowed 45 days after notice to the 
19    Commission. Such notice shall be given by filing with the 
20    Commission on the Commission's e-docket system, and 
21    keeping open for public inspection the award for 
22    compensation proposed by the Administrator. The Commission 
23    shall have power, and it is hereby given authority, either 
24    upon complaint or upon its own initiative without 
25    complaint, at once, and if it so orders, without answer or 
26    other formal pleadings, but upon reasonable notice, to 
 
 
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1    enter upon a hearing concerning the propriety of the 
2    award.
3        (3) A consumer interest representative who performed 
4    work or otherwise incurred expenses in an eligible 
5    proceeding before the Commission prior to the effective 
6    date of this amendatory Act of the 104th General Assembly 
7    and after September 15, 2021 (the effective date of Public 
8    Act 102-662) and who, due to a denied application or 
9    otherwise, was not awarded compensation for the entirety 
10    of the incurred expenses from the Consumer Intervenor 
11    Compensation Fund may seek compensation from the Consumer 
12    Intervenor Compensation Fund pursuant to this Section. 
13    Nothing in this Section shall prohibit retroactive awards 
14    to eligible participants for work performed or expenses 
15    incurred in eligible proceedings prior to the effective 
16    date of this amendatory Act of the 104th General Assembly 
17    and after September 15, 2021 (the effective date of Public 
18    Act 102-662). The retroactive awards shall not include 
19    additional costs directly or indirectly incurred due to 
20    the prior denial of an application for an eligible 
21    proceeding. Applications for a retroactive award shall be 
22    subject to the revised eligibility standards enacted 
23    pursuant to this amendatory Act of the 104th General 
24    Assembly. The applications may be submitted at any time 
25    within one calendar year after the effective date of this 
26    amendatory Act of the 104th General Assembly.    
 
 
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1    (c) The Commission may adopt rules to implement this 
2Section.
3(Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)
 
4    (220 ILCS 5/16-107.5)
5    Sec. 16-107.5. Net electricity metering.
6    (a) The General Assembly finds and declares that a program 
7to provide net electricity metering, as defined in this 
8Section, for eligible customers can encourage private 
9investment in renewable energy resources, stimulate economic 
10growth, enhance the continued diversification of Illinois' 
11energy resource mix, and protect the Illinois environment. 
12Further, to achieve the goals of this Act that robust options 
13for customer-site distributed generation and storage continue 
14to thrive in Illinois, the General Assembly finds that a 
15predictable transition must be ensured for customers between 
16full net metering at the retail electricity rate to the 
17distribution generation rebate described in Section 16-107.6. 
18    (b) As used in this Section: ,    
19        (i) "Community community renewable generation project" 
20    shall have the meaning set forth in Section 1-10 of the 
21    Illinois Power Agency Act. ;    
22        (ii) "Eligible eligible customer" means a retail 
23    customer that owns, hosts, or operates, including any 
24    third-party owned systems, a solar, wind, or other 
25    eligible renewable electrical generating facility or an 
 
 
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1    eligible storage device that is located on the customer's 
2    premises or customer's side of the billing meter and is 
3    intended primarily to offset the customer's own current or 
4    future electrical requirements. ;    
5        (iii) "Electricity electricity provider" means an 
6    electric utility or alternative retail electric supplier. ;    
7        (iv) "Eligible eligible renewable electrical 
8    generating facility" means a generator, which may include 
9    the colocation co-location of an energy storage system, 
10    that is interconnected under rules adopted by the 
11    Commission and is powered by solar electric energy, wind, 
12    dedicated crops grown for electricity generation, 
13    agricultural residues, untreated and unadulterated wood 
14    waste, livestock manure, anaerobic digestion of livestock 
15    or food processing waste, fuel cells or microturbines 
16    powered by renewable fuels, or hydroelectric energy. ;    
17        (v) "Net net electricity metering" (or "net metering") 
18    means the measurement, during the billing period 
19    applicable to an eligible customer, of the net amount of 
20    electricity supplied by an electricity provider to the 
21    customer or provided to the electricity provider by the 
22    customer or subscriber. ;    
23        (vi) "Subscriber subscriber" shall have the meaning as 
24    set forth in Section 1-10 of the Illinois Power Agency 
25    Act. ;    
26        (vii) "Subscription subscription" shall have the 
 
 
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1    meaning set forth in Section 1-10 of the Illinois Power 
2    Agency Act. ;    
3        (viii) "Energy energy storage system" means 
4    commercially available technology that is capable of 
5    absorbing energy and storing it for a period of time for 
6    use at a later time, including, but not limited to, 
7    electrochemical, thermal, and electromechanical 
8    technologies, and may be interconnected behind the 
9    customer's meter or interconnected behind its own meter. ; 
10    and    
11        (ix) "Future future electrical requirements" means 
12    modeled electrical requirements upon occupation of a new 
13    or vacant property, and other reasonable expectations of 
14    future electrical use, as well as, for occupied 
15    properties, a reasonable approximation of the annual load 
16    of 2 electric vehicles and, for non-electric heating 
17    customers, a reasonable approximation of the incremental 
18    electric load associated with fuel switching. The 
19    approximations shall be applied to the appropriate net 
20    metering tariff and do not need to be unique to each 
21    individual eligible customer. The utility shall submit 
22    these approximations to the Commission for review, 
23    modification, and approval.
24        (x) "Vehicle storage system" means a vehicle that when 
25    connected to an electric utility's distribution system is 
26    capable of being an energy storage system, as defined in 
 
 
10400SB0025ham002- 569 -LRB104 07069 AAS 28576 a

1    Section 16-107.6.    
2    (c) A net metering facility shall be equipped with 
3metering equipment that can measure the flow of electricity in 
4both directions at the same rate.
5        (1) For eligible customers whose electric service has 
6    not been declared competitive pursuant to Section 16-113 
7    of this Act as of July 1, 2011 and whose electric delivery 
8    service is provided and measured on a kilowatt-hour basis 
9    and electric supply service is not provided based on 
10    hourly pricing, this shall typically be accomplished 
11    through use of a single, bi-directional meter. If the 
12    eligible customer's existing electric revenue meter does 
13    not meet this requirement, the electricity provider shall 
14    arrange for the local electric utility or a meter service 
15    provider to install and maintain a new revenue meter at 
16    the electricity provider's expense, which may be the smart 
17    meter described by subsection (b) of Section 16-108.5 of 
18    this Act.
19        (2) For eligible customers whose electric service has 
20    not been declared competitive pursuant to Section 16-113 
21    of this Act as of July 1, 2011 and whose electric delivery 
22    service is provided and measured on a kilowatt demand 
23    basis and electric supply service is not provided based on 
24    hourly pricing, this shall typically be accomplished 
25    through use of a dual channel meter capable of measuring 
26    the flow of electricity both into and out of the 
 
 
10400SB0025ham002- 570 -LRB104 07069 AAS 28576 a

1    customer's facility at the same rate and ratio. If such 
2    customer's existing electric revenue meter does not meet 
3    this requirement, then the electricity provider shall 
4    arrange for the local electric utility or a meter service 
5    provider to install and maintain a new revenue meter at 
6    the electricity provider's expense, which may be the smart 
7    meter described by subsection (b) of Section 16-108.5 of 
8    this Act.
9        (3) For all other eligible customers, until such time 
10    as the local electric utility installs a smart meter, as 
11    described by subsection (b) of Section 16-108.5 of this 
12    Act, the electricity provider may arrange for the local 
13    electric utility or a meter service provider to install 
14    and maintain metering equipment capable of measuring the 
15    flow of electricity both into and out of the customer's 
16    facility at the same rate and ratio, typically through the 
17    use of a dual channel meter. If the eligible customer's 
18    existing electric revenue meter does not meet this 
19    requirement, then the costs of installing such equipment 
20    shall be paid for by the customer. 
21    (d) An electricity provider shall measure and charge or 
22credit for the net electricity supplied to eligible customers 
23or provided by eligible customers whose electric service has 
24not been declared competitive pursuant to Section 16-113 of 
25this Act as of July 1, 2011 and whose electric delivery service 
26is provided and measured on a kilowatt-hour basis and electric 
 
 
10400SB0025ham002- 571 -LRB104 07069 AAS 28576 a

1supply service is not provided based on hourly pricing in the 
2following manner:
3        (1) If the amount of electricity used by the customer 
4    during the billing period exceeds the amount of 
5    electricity produced by the customer, the electricity 
6    provider shall charge the customer for the net electricity 
7    supplied to and used by the customer as provided in 
8    subsection (e-5) of this Section.
9        (2) If the amount of electricity produced by a 
10    customer during the billing period exceeds the amount of 
11    electricity used by the customer during that billing 
12    period, the electricity provider supplying that customer 
13    shall apply a 1:1 kilowatt-hour credit to a subsequent 
14    bill for service to the customer for the net electricity 
15    supplied to the electricity provider. The electricity 
16    provider shall continue to carry over any excess 
17    kilowatt-hour credits earned and apply those credits to 
18    subsequent billing periods to offset any 
19    customer-generator consumption in those billing periods 
20    until all credits are used or until the end of the 
21    annualized period.
22        (3) At the end of the year or annualized over the 
23    period that service is supplied by means of net metering, 
24    or in the event that the retail customer terminates 
25    service with the electricity provider prior to the end of 
26    the year or the annualized period, any remaining credits 
 
 
10400SB0025ham002- 572 -LRB104 07069 AAS 28576 a

1    in the customer's account shall expire.
2    (d-5) An electricity provider shall measure and charge or 
3credit for the net electricity supplied to eligible customers 
4or provided by eligible customers whose electric service has 
5not been declared competitive pursuant to Section 16-113 of 
6this Act as of July 1, 2011 and whose electric delivery service 
7is provided and measured on a kilowatt-hour basis and electric 
8supply service is provided based on hourly pricing or 
9time-of-use rates in the following manner:
10        (1) If the amount of electricity used by the customer 
11    during any hourly period or time-of-use period exceeds the 
12    amount of electricity produced by the customer, the 
13    electricity provider shall charge the customer for the net 
14    electricity supplied to and used by the customer according 
15    to the terms of the contract or tariff to which the same 
16    customer would be assigned to or be eligible for if the 
17    customer was not a net metering customer.
18        (2) If the amount of electricity produced by a 
19    customer during any hourly period or time-of-use period 
20    exceeds the amount of electricity used by the customer 
21    during that hourly period or time-of-use period, the 
22    energy provider shall apply a credit for the net 
23    kilowatt-hours produced in such period. The credit shall 
24    consist of an energy credit and a delivery service credit. 
25    The energy credit shall be valued at the same price per 
26    kilowatt-hour as the electric service provider would 
 
 
10400SB0025ham002- 573 -LRB104 07069 AAS 28576 a

1    charge for kilowatt-hour energy sales during that same 
2    hourly period or time-of-use period. The delivery credit 
3    shall be equal to the net kilowatt-hours produced in such 
4    hourly period or time-of-use period times a credit that 
5    reflects all kilowatt-hour based charges in the customer's 
6    electric service rate, excluding energy charges. 
7    (e) An electricity provider shall measure and charge or 
8credit for the net electricity supplied to eligible customers 
9whose electric service has not been declared competitive 
10pursuant to Section 16-113 of this Act as of July 1, 2011 and 
11whose electric delivery service is provided and measured on a 
12kilowatt demand basis and electric supply service is not 
13provided based on hourly pricing in the following manner:
14        (1) If the amount of electricity used by the customer 
15    during the billing period exceeds the amount of 
16    electricity produced by the customer, then the electricity 
17    provider shall charge the customer for the net electricity 
18    supplied to and used by the customer as provided in 
19    subsection (e-5) of this Section. The customer shall 
20    remain responsible for all taxes, fees, and utility 
21    delivery charges that would otherwise be applicable to the 
22    net amount of electricity used by the customer.
23        (2) If the amount of electricity produced by a 
24    customer during the billing period exceeds the amount of 
25    electricity used by the customer during that billing 
26    period, then the electricity provider supplying that 
 
 
10400SB0025ham002- 574 -LRB104 07069 AAS 28576 a

1    customer shall apply a 1:1 kilowatt-hour credit that 
2    reflects the kilowatt-hour based charges in the customer's 
3    electric service rate to a subsequent bill for service to 
4    the customer for the net electricity supplied to the 
5    electricity provider. The electricity provider shall 
6    continue to carry over any excess kilowatt-hour credits 
7    earned and apply those credits to subsequent billing 
8    periods to offset any customer-generator consumption in 
9    those billing periods until all credits are used or until 
10    the end of the annualized period.
11        (3) At the end of the year or annualized over the 
12    period that service is supplied by means of net metering, 
13    or in the event that the retail customer terminates 
14    service with the electricity provider prior to the end of 
15    the year or the annualized period, any remaining credits 
16    in the customer's account shall expire.
17    (e-5) An electricity provider shall provide electric 
18service to eligible customers who utilize net metering at 
19non-discriminatory rates that are identical, with respect to 
20rate structure, retail rate components, and any monthly 
21charges, to the rates that the customer would be charged if not 
22a net metering customer. An electricity provider shall not 
23charge net metering customers any fee or charge or require 
24additional equipment, insurance, or any other requirements not 
25specifically authorized by interconnection standards 
26authorized by the Commission, unless the fee, charge, or other 
 
 
10400SB0025ham002- 575 -LRB104 07069 AAS 28576 a

1requirement would apply to other similarly situated customers 
2who are not net metering customers. The customer will remain 
3responsible for all taxes, fees, and utility delivery charges 
4that would otherwise be applicable to the net amount of 
5electricity used by the customer. Subsections (c) through (e) 
6of this Section shall not be construed to prevent an 
7arms-length agreement between an electricity provider and an 
8eligible customer that sets forth different prices, terms, and 
9conditions for the provision of net metering service, 
10including, but not limited to, the provision of the 
11appropriate metering equipment for non-residential customers.
12    (f) Notwithstanding the requirements of subsections (c) 
13through (e-5) of this Section, an electricity provider must 
14require dual-channel metering for customers operating eligible 
15renewable electrical generating facilities to whom the 
16provisions of neither subsection (d), (d-5), nor (e) of this 
17Section apply. In such cases, electricity charges and credits 
18shall be determined as follows: 
19        (1) The electricity provider shall assess and the 
20    customer remains responsible for all taxes, fees, and 
21    utility delivery charges that would otherwise be 
22    applicable to the gross amount of kilowatt-hours supplied 
23    to the eligible customer by the electricity provider.
24        (2) Each month that service is supplied by means of 
25    dual-channel metering, the electricity provider shall 
26    compensate the eligible customer for any excess 
 
 
10400SB0025ham002- 576 -LRB104 07069 AAS 28576 a

1    kilowatt-hour credits at the electricity provider's 
2    avoided cost of electricity supply over the monthly period 
3    or as otherwise specified by the terms of a power-purchase 
4    agreement negotiated between the customer and electricity 
5    provider.
6        (3) For all eligible net metering customers taking 
7    service from an electricity provider under contracts or 
8    tariffs employing hourly or time-of-use rates, any monthly 
9    consumption of electricity shall be calculated 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. When those same 
13    customer-generators are net generators during any discrete 
14    hourly or time-of-use period, the net kilowatt-hours 
15    produced shall be valued at the same price per 
16    kilowatt-hour as the electric service provider would 
17    charge for retail kilowatt-hour sales during that same 
18    time-of-use period. 
19    (g) For purposes of federal and State laws providing 
20renewable energy credits or greenhouse gas credits, the 
21eligible customer shall be treated as owning and having title 
22to the renewable energy attributes, renewable energy credits, 
23and greenhouse gas emission credits related to any electricity 
24produced by the qualified generating unit. The electricity 
25provider may not condition participation in a net metering 
26program on the signing over of a customer's renewable energy 
 
 
10400SB0025ham002- 577 -LRB104 07069 AAS 28576 a

1credits; provided, however, this subsection (g) shall not be 
2construed to prevent an arms-length agreement between an 
3electricity provider and an eligible customer that sets forth 
4the ownership or title of the credits.
5    (h) Within 120 days after the effective date of this 
6amendatory Act of the 95th General Assembly, the Commission 
7shall establish standards for net metering and, if the 
8Commission has not already acted on its own initiative, 
9standards for the interconnection of eligible renewable 
10generating equipment to the utility system. The 
11interconnection standards shall address any procedural 
12barriers, delays, and administrative costs associated with the 
13interconnection of customer-generation while ensuring the 
14safety and reliability of the units and the electric utility 
15system. The Commission shall consider the Institute of 
16Electrical and Electronics Engineers (IEEE) Standard 1547 and 
17the issues of (i) reasonable and fair fees and costs, (ii) 
18clear timelines for major milestones in the interconnection 
19process, (iii) nondiscriminatory terms of agreement, and (iv) 
20any best practices for interconnection of distributed 
21generation.
22    (h-5) Within 90 days after the effective date of this 
23amendatory Act of the 102nd General Assembly, the Commission 
24shall: 
25        (1) establish an Interconnection Working Group. The 
26    working group shall include representatives from electric 
 
 
10400SB0025ham002- 578 -LRB104 07069 AAS 28576 a

1    utilities, developers of renewable electric generating 
2    facilities, other industries that regularly apply for 
3    interconnection with the electric utilities, 
4    representatives of distributed generation customers, the 
5    Commission Staff, and such other stakeholders with a 
6    substantial interest in the topics addressed by the 
7    Interconnection Working Group. The Interconnection Working 
8    Group shall address at least the following issues:
9            (A) cost and best available technology for 
10        interconnection and metering, including the 
11        standardization and publication of standard costs;
12            (B) transparency, accuracy and use of the 
13        distribution interconnection queue and hosting 
14        capacity maps;
15            (C) distribution system upgrade cost avoidance 
16        through use of advanced inverter functions;
17            (D) predictability of the queue management process 
18        and enforcement of timelines;
19            (E) benefits and challenges associated with group 
20        studies and cost sharing;
21            (F) minimum requirements for application to the 
22        interconnection process and throughout the 
23        interconnection process to avoid queue clogging 
24        behavior;
25            (G) process and customer service for 
26        interconnecting customers adopting distributed energy 
 
 
10400SB0025ham002- 579 -LRB104 07069 AAS 28576 a

1        resources, including energy storage;
2            (H) options for metering distributed energy 
3        resources, including energy storage;
4            (I) interconnection of new technologies, including 
5        smart inverters and energy storage;
6            (J) collect, share, and examine data on Level 1 
7        interconnection costs, including cost and type of 
8        upgrades required for interconnection, and use this 
9        data to inform the final standardized cost of Level 1 
10        interconnection; and
11            (K) such other technical, policy, and tariff 
12        issues related to and affecting interconnection 
13        performance and customer service as determined by the 
14        Interconnection Working Group. 
15        The Commission may create subcommittees of the 
16    Interconnection Working Group to focus on specific issues 
17    of importance, as appropriate. The Interconnection Working 
18    Group shall report to the Commission on recommended 
19    improvements to interconnection rules and tariffs and 
20    policies as determined by the Interconnection Working 
21    Group at least every 6 months. Such reports shall include 
22    consensus recommendations of the Interconnection Working 
23    Group and, if applicable, additional recommendations for 
24    which consensus was not reached. The Commission shall use 
25    the report from the Interconnection Working Group to 
26    determine whether processes should be commenced to 
 
 
10400SB0025ham002- 580 -LRB104 07069 AAS 28576 a

1    formally codify or implement the recommendations;
2        (2) create or contract for an Ombudsman to resolve 
3    interconnection disputes through non-binding arbitration. 
4    The Ombudsman may be paid in full or in part through fees 
5    levied on the initiators of the dispute; and
6        (3) determine a single standardized cost for Level 1 
7    interconnections, which shall not exceed $200. 
8    (i) All electricity providers shall begin to offer net 
9metering no later than April 1, 2008.
10    (j) An electricity provider shall provide net metering to 
11eligible customers according to subsections (d), (d-5), and 
12(e). Eligible renewable electrical generating facilities for 
13which eligible customers registered for net metering before 
14January 1, 2025 shall continue to receive net metering 
15services according to subsections (d), (d-5), and (e) of this 
16Section for the lifetime of the system, regardless of whether 
17those retail customers change electricity providers or whether 
18the retail customer benefiting from the system changes. On and 
19after January 1, 2025, any eligible customer that applies for 
20net metering and previously would have qualified under 
21subsections (d), (d-5), or (e) shall only be eligible for net 
22metering as described in subsection (n). 
23    (k) Each electricity provider shall maintain records and 
24report annually to the Commission the total number of net 
25metering customers served by the provider, as well as the 
26type, capacity, and energy sources of the generating systems 
 
 
10400SB0025ham002- 581 -LRB104 07069 AAS 28576 a

1used by the net metering customers. Nothing in this Section 
2shall limit the ability of an electricity provider to request 
3the redaction of information deemed by the Commission to be 
4confidential business information.
5    (l)(1) Notwithstanding the definition of "eligible 
6customer" in item (ii) of subsection (b) of this Section, each 
7electricity provider shall allow net metering as set forth in 
8this subsection (l) and for the following projects, provided 
9that only electric utilities serving more than 200,000 
10customers as of January 1, 2021 shall provide net metering for 
11projects that are eligible for subparagraph (C) of this 
12paragraph (1) and have energized after the effective date of 
13this amendatory Act of the 102nd General Assembly: 
14        (A) properties owned or leased by multiple customers 
15    that contribute to the operation of an eligible renewable 
16    electrical generating facility through an ownership or 
17    leasehold interest of at least 200 watts in such facility, 
18    such as a community-owned wind project, a community-owned 
19    biomass project, a community-owned solar project, or a 
20    community methane digester processing livestock waste from 
21    multiple sources, provided that the facility is also 
22    located within the utility's service territory; 
23        (B) individual units, apartments, or properties 
24    located in a single building that are owned or leased by 
25    multiple customers and collectively served by a common 
26    eligible renewable electrical generating facility, such as 
 
 
10400SB0025ham002- 582 -LRB104 07069 AAS 28576 a

1    an office or apartment building, a shopping center or 
2    strip mall served by photovoltaic panels on the roof; and 
3        (C) subscriptions to community renewable generation 
4    projects, including community renewable generation 
5    projects on the customer's side of the billing meter of a 
6    host facility and partially used for the customer's own 
7    load.
8    In addition, the nameplate capacity of the eligible 
9renewable electric generating facility that serves the demand 
10of the properties, units, or apartments identified in 
11paragraphs (1) and (2) of this subsection (l) shall not exceed 
125,000 kilowatts in nameplate capacity in total. Any eligible 
13renewable electrical generating facility or community 
14renewable generation project that is powered by photovoltaic 
15electric energy and installed after the effective date of this 
16amendatory Act of the 99th General Assembly must be installed 
17by a qualified person in compliance with the requirements of 
18Section 16-128A of the Public Utilities Act and any rules or 
19regulations adopted thereunder.
20    (2) Notwithstanding anything to the contrary, an 
21electricity provider shall provide credits for the electricity 
22produced by the projects described in paragraph (1) of this 
23subsection (l). The electricity provider shall provide credits 
24that include at least energy supply, capacity, transmission, 
25and, if applicable, the purchased energy adjustment on the 
26subscriber's monthly bill equal to the subscriber's share of 
 
 
10400SB0025ham002- 583 -LRB104 07069 AAS 28576 a

1the production of electricity from the project, as determined 
2by paragraph (3) of this subsection (l). For customers with 
3transmission or capacity charges not charged on a 
4kilowatt-hour basis, the electricity provider shall prepare a 
5reasonable approximation of the kilowatt-hour equivalent value 
6and provide that value as a monetary credit. The electricity 
7provider shall submit these approximation methodologies to the 
8Commission for review, modification, and approval. 
9Notwithstanding anything to the contrary, customers on payment 
10plans or participating in budget billing programs shall have 
11credits applied on a monthly basis. 
12    (3) Notwithstanding anything to the contrary and 
13regardless of whether a subscriber to an eligible community 
14renewable generation project receives power and energy service 
15from the electric utility or an alternative retail electric 
16supplier, for projects eligible under paragraph (C) of 
17subparagraph (1) of this subsection (l), electric utilities 
18serving more than 200,000 customers as of January 1, 2021 
19shall provide the monetary credits to a subscriber's 
20subsequent bill for the electricity produced by community 
21renewable generation projects. The electric utility shall 
22provide monetary credits to a subscriber's subsequent bill at 
23the utility's total price to compare equal to the subscriber's 
24share of the production of electricity from the project, as 
25determined by paragraph (5) of this subsection (l). For the 
26purposes of this subsection, "total price to compare" means 
 
 
10400SB0025ham002- 584 -LRB104 07069 AAS 28576 a

1the rate or rates published by the Illinois Commerce 
2Commission for energy supply for eligible customers receiving 
3supply service from the electric utility, and shall include 
4energy, capacity, transmission, and the purchased energy 
5adjustment. Notwithstanding anything to the contrary, 
6customers on payment plans or participating in budget billing 
7programs shall have credits applied on a monthly basis. Any 
8applicable credit or reduction in load obligation from the 
9production of the community renewable generating projects 
10receiving a credit under this subsection shall be credited to 
11the electric utility to offset the cost of providing the 
12credit. To the extent that the credit or load obligation 
13reduction does not completely offset the cost of providing the 
14credit to subscribers of community renewable generation 
15projects as described in this subsection, the electric utility 
16may recover the remaining costs through its Multi-Year Rate 
17Plan. All electric utilities serving 200,000 or fewer 
18customers as of January 1, 2021 shall only provide the 
19monetary credits to a subscriber's subsequent bill for the 
20electricity produced by community renewable generation 
21projects if the subscriber receives power and energy service 
22from the electric utility. Alternative retail electric 
23suppliers providing power and energy service to a subscriber 
24located within the service territory of an electric utility 
25not subject to Sections 16-108.18 and 16-118 shall provide the 
26monetary credits to the subscriber's subsequent bill for the 
 
 
10400SB0025ham002- 585 -LRB104 07069 AAS 28576 a

1electricity produced by community renewable generation 
2projects.
3    (4) If requested by the owner or operator of a community 
4renewable generating project, an electric utility serving more 
5than 200,000 customers as of January 1, 2021 shall enter into a 
6net crediting agreement with the owner or operator to include 
7a subscriber's subscription fee on the subscriber's monthly 
8electric bill and provide the subscriber with a net credit 
9equivalent to the total bill credit value for that generation 
10period minus the subscription fee, provided the subscription 
11fee is structured as a fixed percentage of bill credit value. 
12The net crediting agreement shall set forth payment terms from 
13the electric utility to the owner or operator of the community 
14renewable generating project, and the electric utility may 
15charge a net crediting fee to the owner or operator of a 
16community renewable generating project that may not exceed 1%    
172% of the subscription fee bill credit value. Notwithstanding 
18anything to the contrary, an electric utility serving 200,000 
19customers or fewer as of January 1, 2021 shall not be obligated 
20to enter into a net crediting agreement with the owner or 
21operator of a community renewable generating project. An 
22electric utility shall use the same net crediting format for 
23subscribers on payment plans and subscribers participating in 
24budget billing programs. For the purposes of this paragraph 
25(4), "net crediting" means a program offered by an electric 
26utility under which the electric utility, upon authorization 
 
 
10400SB0025ham002- 586 -LRB104 07069 AAS 28576 a

1by or on behalf of a subscriber, remits the cash value of the 
2subscription fee to the owner or operator of the community 
3renewable generation facility without regard to whether the 
4subscriber has paid the subscriber's monthly electric bill and 
5places the cash value of the remaining bill credit on the 
6subscriber's bill.    
7    (5) For the purposes of facilitating net metering, the 
8owner or operator of the eligible renewable electrical 
9generating facility or community renewable generation project 
10shall be responsible for determining the amount of the credit 
11that each customer or subscriber participating in a project 
12under this subsection (l) is to receive in the following 
13manner: 
14        (A) The owner or operator shall, on a monthly basis, 
15    provide to the electric utility the kilowatthours of 
16    generation attributable to each of the utility's retail 
17    customers and subscribers participating in projects under 
18    this subsection (l) in accordance with the customer's or 
19    subscriber's share of the eligible renewable electric 
20    generating facility's or community renewable generation 
21    project's output of power and energy for such month. The 
22    owner or operator shall electronically transmit such 
23    calculations and associated documentation to the electric 
24    utility, in a format or method set forth in the applicable 
25    tariff, on a monthly basis so that the electric utility 
26    can reflect the monetary credits on customers' and 
 
 
10400SB0025ham002- 587 -LRB104 07069 AAS 28576 a

1    subscribers' electric utility bills. The electric utility 
2    shall be permitted to revise its tariffs to implement the 
3    provisions of this amendatory Act of the 102nd General 
4    Assembly. The owner or operator shall separately provide 
5    the electric utility with the documentation detailing the 
6    calculations supporting the credit in the manner set forth 
7    in the applicable tariff. 
8        (B) For those participating customers and subscribers 
9    who receive their energy supply from an alternative retail 
10    electric supplier, the electric utility shall remit to the 
11    applicable alternative retail electric supplier the 
12    information provided under subparagraph (A) of this 
13    paragraph (3) for such customers and subscribers in a 
14    manner set forth in such alternative retail electric 
15    supplier's net metering program, or as otherwise agreed 
16    between the utility and the alternative retail electric 
17    supplier. The alternative retail electric supplier shall 
18    then submit to the utility the amount of the charges for 
19    power and energy to be applied to such customers and 
20    subscribers, including the amount of the credit associated 
21    with net metering. 
22        (C) A participating customer or subscriber may provide 
23    authorization as required by applicable law that directs 
24    the electric utility to submit information to the owner or 
25    operator of the eligible renewable electrical generating 
26    facility or community renewable generation project to 
 
 
10400SB0025ham002- 588 -LRB104 07069 AAS 28576 a

1    which the customer or subscriber has an ownership or 
2    leasehold interest or a subscription. Such information 
3    shall be limited to the components of the net metering 
4    credit calculated under this subsection (l), including the 
5    bill credit rate, total kilowatthours, and total monetary 
6    credit value applied to the customer's or subscriber's 
7    bill for the monthly billing period. 
8    (l-5) Within 90 days after the effective date of this 
9amendatory Act of the 102nd General Assembly, each electric 
10utility subject to this Section shall file a tariff or tariffs 
11to implement the provisions of subsection (l) of this Section, 
12which shall, consistent with the provisions of subsection (l), 
13describe the terms and conditions under which owners or 
14operators of qualifying properties, units, or apartments may 
15participate in net metering. The Commission shall approve, or 
16approve with modification, the tariff within 120 days after 
17the effective date of this amendatory Act of the 102nd General 
18Assembly. 
19    (l-10) Each electricity provider shall allow net metering 
20as set forth in this subsection for an energy storage system or 
21vehicle storage system energized after the effective date of 
22this amendatory Act of the 104th General Assembly with a 
23nameplate capacity of not more than 5,000 kilowatts.    
24    An energy storage system or vehicle storage system 
25eligible for net metering under this subsection may be 
26interconnected behind the meter of a retail customer or at the 
 
 
10400SB0025ham002- 589 -LRB104 07069 AAS 28576 a

1distribution system level of an electric utility as follows:
2        (A) if the energy storage system or vehicle storage 
3    system is interconnected behind the meter of a retail 
4    customer, in order to receive net metering under this 
5    subsection, the eligible customer behind whose meter the 
6    energy storage system is interconnected must receive 
7    service from an electricity provider under an hourly 
8    supply tariff, a time-of-use supply tariff, or a 
9    time-of-use contract with an alternative retail electric 
10    supplier; or
11        (B) if the energy storage system or vehicle storage 
12    system is interconnected at the distribution system level 
13    of an electric utility and not behind the meter of a retail 
14    customer, the energy storage system or vehicle storage 
15    system must receive service from an electricity provider 
16    as a retail customer under an hourly supply tariff 
17    authorized by Section 16-107, a supply tariff or contract 
18    on substantially similar terms and conditions with an 
19    alternative retail electric supplier, a time-of-use supply 
20    tariff, or a time-of-use supply contract with an 
21    alternative retail electric supplier.
22    If the energy storage system or vehicle storage system is 
23interconnected behind the meter of an eligible customer, the 
24eligible customer shall receive net metering based on hourly 
25or time-of-use rates in accordance with the terms of 
26subsection (d-5) or (f) or paragraph (2) of subsection (n) of 
 
 
10400SB0025ham002- 590 -LRB104 07069 AAS 28576 a

1this Section, as applicable to the eligible customer. If the 
2energy storage system or vehicle storage system is 
3interconnected at the distribution system level of an electric 
4utility and not behind the meter of a retail customer, then the 
5energy storage system or vehicle storage system shall receive 
6net metering pursuant to the terms of subsection (f) of this 
7Section.    
8    (m) Nothing in this Section shall affect the right of an 
9electricity provider to continue to provide, or the right of a 
10retail customer to continue to receive service pursuant to a 
11contract for electric service between the electricity provider 
12and the retail customer in accordance with the prices, terms, 
13and conditions provided for in that contract. Either the 
14electricity provider or the customer may require compliance 
15with the prices, terms, and conditions of the contract. 
16    (n) On and after January 1, 2025, the net metering 
17services described in subsections (d), (d-5), and (e) of this 
18Section shall no longer be offered, except as to those 
19eligible renewable electrical generating facilities for which 
20retail customers are receiving net metering service under 
21these subsections at the time the net metering services under 
22those subsections are no longer offered; those systems shall 
23continue to receive net metering services described in 
24subsections (d), (d-5), and (e) of this Section for the 
25lifetime of the system, regardless of if those retail 
26customers change electricity providers or whether the retail 
 
 
10400SB0025ham002- 591 -LRB104 07069 AAS 28576 a

1customer benefiting from the system changes. The electric 
2utility serving more than 200,000 customers as of January 1, 
32021 is responsible for ensuring the billing credits continue 
4without lapse for the lifetime of systems, as required in 
5subsection (o). Those retail customers that begin taking net 
6metering service after the date that net metering services are 
7no longer offered under such subsections shall be subject to 
8the provisions set forth in the following paragraphs (1) 
9through (3) of this subsection (n):
10        (1) An electricity provider shall charge or credit for 
11    the net electricity supplied to eligible customers or 
12    provided by eligible customers whose electric supply 
13    service is not provided based on hourly pricing in the 
14    following manner:
15            (A) If the amount of electricity used by the 
16        customer during the monthly billing period exceeds the 
17        amount of electricity produced by the customer, then 
18        the electricity provider shall charge the customer for 
19        the net kilowatt-hour based electricity charges 
20        reflected in the customer's electric service rate 
21        supplied to and used by the customer as provided in 
22        paragraph (3) of this subsection (n).
23            (B) If the amount of electricity produced by a 
24        customer during the monthly billing period exceeds the 
25        amount of electricity used by the customer during that 
26        billing period, then the electricity provider 
 
 
10400SB0025ham002- 592 -LRB104 07069 AAS 28576 a

1        supplying that customer shall apply a 1:1 
2        kilowatt-hour energy or monetary credit kilowatt-hour 
3        supply charges to the customer's subsequent bill. The 
4        customer shall choose between 1:1 kilowatt-hour or 
5        monetary credit at the time of application. For the 
6        purposes of this subsection, "kilowatt-hour supply 
7        charges" means the kilowatt-hour equivalent values for 
8        energy, capacity, transmission, and the purchased 
9        energy adjustment, if applicable. Notwithstanding 
10        anything to the contrary, customers on payment plans 
11        or participating in budget billing programs shall have 
12        credits applied on a monthly basis. The electricity 
13        provider shall continue to carry over any excess 
14        kilowatt-hour or monetary energy credits earned and 
15        apply those credits to subsequent billing periods. For 
16        customers with transmission or capacity charges not 
17        charged on a kilowatt-hour basis, the electricity 
18        provider shall prepare a reasonable approximation of 
19        the kilowatt-hour equivalent value and provide that 
20        value as a monetary credit. The electricity provider 
21        shall submit these approximation methodologies to the 
22        Commission for review, modification, and approval.
23            (C) (Blank).
24        (2) An electricity provider shall charge or credit for 
25    the net electricity supplied to eligible customers or 
26    provided by eligible customers whose electric supply 
 
 
10400SB0025ham002- 593 -LRB104 07069 AAS 28576 a

1    service is provided based on hourly pricing in the 
2    following manner:
3            (A) If the amount of electricity used by the 
4        customer during any hourly period exceeds the amount 
5        of electricity produced by the customer, then the 
6        electricity provider shall charge the customer for the 
7        net electricity supplied to and used by the customer 
8        as provided in paragraph (3) of this subsection (n).
9            (B) If the amount of electricity produced by a 
10        customer during any hourly period exceeds the amount 
11        of electricity used by the customer during that hourly 
12        period, the energy provider shall calculate an energy 
13        credit for the net kilowatt-hours produced in such 
14        period, and shall apply that credit as a monetary 
15        credit to the customer's subsequent bill. The value of 
16        the energy credit shall be calculated using the same 
17        price per kilowatt-hour as the electric service 
18        provider would charge for kilowatt-hour energy sales 
19        during that same hourly period and shall also include 
20        values for capacity and transmission. For customers 
21        with transmission or capacity charges not charged on a 
22        kilowatt-hour basis, the electricity provider shall 
23        prepare a reasonable approximation of the 
24        kilowatt-hour equivalent value and provide that value 
25        as a monetary credit. The electricity provider shall 
26        submit these approximation methodologies to the 
 
 
10400SB0025ham002- 594 -LRB104 07069 AAS 28576 a

1        Commission for review, modification, and approval. 
2        Notwithstanding anything to the contrary, customers on 
3        payment plans or participating in budget billing 
4        programs shall have credits applied on a monthly 
5        basis. 
6        (3) An electricity provider shall provide electric 
7    service to eligible customers who utilize net metering at 
8    non-discriminatory rates that are identical, with respect 
9    to rate structure, retail rate components, and any monthly 
10    charges, to the rates that the customer would be charged 
11    if not a net metering customer. An electricity provider 
12    shall charge the customer for the net electricity supplied 
13    to and used by the customer according to the terms of the 
14    contract or tariff to which the same customer would be 
15    assigned or be eligible for if the customer was not a net 
16    metering customer. An electricity provider shall not 
17    charge net metering customers any fee or charge or require 
18    additional equipment, insurance, or any other requirements 
19    not specifically authorized by interconnection standards 
20    authorized by the Commission, unless the fee, charge, or 
21    other requirement would apply to other similarly situated 
22    customers who are not net metering customers. The customer 
23    remains responsible for the gross amount of delivery 
24    services charges, supply-related charges that are kilowatt 
25    based, and all taxes and fees related to such charges. The 
26    customer also remains responsible for all taxes and fees 
 
 
10400SB0025ham002- 595 -LRB104 07069 AAS 28576 a

1    that would otherwise be applicable to the net amount of 
2    electricity used by the customer. Paragraphs (1) and (2) 
3    of this subsection (n) shall not be construed to prevent 
4    an arms-length agreement between an electricity provider 
5    and an eligible customer that sets forth different prices, 
6    terms, and conditions for the provision of net metering 
7    service, including, but not limited to, the provision of 
8    the appropriate metering equipment for non-residential 
9    customers. Nothing in this paragraph (3) shall be 
10    interpreted to mandate that a utility that is only 
11    required to provide delivery services to a given customer 
12    must also sell electricity to such customer. 
13    (o) Within 90 days after the effective date of this 
14amendatory Act of the 102nd General Assembly, each electric 
15utility subject to this Section shall file a tariff, which 
16shall, consistent with the provisions of this Section, propose 
17the terms and conditions under which a customer may 
18participate in net metering. The tariff for electric utilities 
19serving more than 200,000 customers as of January 1, 2021 
20shall also provide a streamlined and transparent bill 
21crediting system for net metering to be managed by the 
22electric utilities. The terms and conditions shall include, 
23but are not limited to, that an electric utility shall manage 
24and maintain billing of net metering credits and charges 
25regardless of if the eligible customer takes net metering 
26under an electric utility or alternative retail electric 
 
 
10400SB0025ham002- 596 -LRB104 07069 AAS 28576 a

1supplier. The electric utility serving more than 200,000 
2customers as of January 1, 2021 shall process and approve all 
3net metering applications, even if an eligible customer is 
4served by an alternative retail electric supplier; and the 
5utility shall forward application approval to the appropriate 
6alternative retail electric supplier. Eligibility for net 
7metering shall remain with the owner of the utility billing 
8address such that, if an eligible renewable electrical 
9generating facility changes ownership, the net metering 
10eligibility transfers to the new owner. The electric utility 
11serving more than 200,000 customers as of January 1, 2021 
12shall manage net metering billing for eligible customers to 
13ensure full crediting occurs on electricity bills, including, 
14but not limited to, ensuring net metering crediting begins 
15upon commercial operation date, net metering billing transfers 
16immediately if an eligible customer switches from an electric 
17utility to alternative retail electric supplier or vice versa, 
18and net metering billing transfers between ownership of a 
19valid billing address. All transfers referenced in the 
20preceding sentence shall include transfer of all banked 
21credits. All electric utilities serving 200,000 or fewer 
22customers as of January 1, 2021 shall manage net metering 
23billing for eligible customers receiving power and energy 
24service from the electric utility to ensure full crediting 
25occurs on electricity bills, ensuring net metering crediting 
26begins upon commercial operation date, net metering billing 
 
 
10400SB0025ham002- 597 -LRB104 07069 AAS 28576 a

1transfers immediately if an eligible customer switches from an 
2electric utility to alternative retail electric supplier or 
3vice versa, and net metering billing transfers between 
4ownership of a valid billing address. Alternative retail 
5electric suppliers providing power and energy service to 
6eligible customers located within the service territory of an 
7electric utility serving 200,000 or fewer customers as of 
8January 1, 2021 shall manage net metering billing for eligible 
9customers to ensure full crediting occurs on electricity 
10bills, including, but not limited to, ensuring net metering 
11crediting begins upon commercial operation date, net metering 
12billing transfers immediately if an eligible customer switches 
13from an electric utility to alternative retail electric 
14supplier or vice versa, and net metering billing transfers 
15between ownership of a valid billing address. 
16(Source: P.A. 102-662, eff. 9-15-21.)
 
17    (220 ILCS 5/16-107.6)
18    Sec. 16-107.6. Distributed generation and storage rebate.
19    (a) In this Section:
20    "Additive services" means the services that distributed 
21energy resources provide to the energy system and society that 
22are described in Section 16-107.9 not (1) already included in 
23the base rebates for system-wide grid services; or (2) 
24otherwise already compensated. Additive services may reflect, 
25but shall not be limited to, any geographic, time-based, 
 
 
10400SB0025ham002- 598 -LRB104 07069 AAS 28576 a

1performance-based, and other benefits of distributed energy 
2resources, as well as the present and future technological 
3capabilities of distributed energy resources and present and 
4future grid needs. 
5    "Distributed energy resource" means a wide range of 
6technologies that are located on the customer side of the 
7customer's electric meter, including, but not limited to, 
8distributed generation, energy storage, electric vehicles, and 
9demand response technologies. 
10    "Energy storage system" means commercially available 
11technology that is capable of absorbing energy and storing it 
12for a period of time for use at a later time, including, but 
13not limited to, electrochemical, thermal, and 
14electromechanical technologies, and may be interconnected 
15behind the customer's meter or interconnected behind its own 
16meter. "Energy storage system" also includes electric vehicle 
17storage systems connected to the distribution grid and capable 
18of discharging to the distribution grid.    
19    "Smart inverter" means a device that converts direct 
20current into alternating current and meets the IEEE 1547-2018 
21equipment standards. Until devices that meet the IEEE 
221547-2018 standard are available, devices that meet the UL 
231741 SA standard are acceptable.
24    "Subscriber" has the meaning set forth in Section 1-10 of 
25the Illinois Power Agency Act.
26    "Subscription" has the meaning set forth in Section 1-10 
 
 
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1of the Illinois Power Agency Act.
2    "System-wide grid services" means the benefits that a 
3distributed energy resource provides to the distribution grid 
4for a period of no less than 25 years. System-wide grid 
5services do not vary by location, time, or the performance 
6characteristics of the distributed energy resource. 
7System-wide grid services include, but are not limited to, 
8avoided or deferred distribution capacity costs, resilience 
9and reliability benefits, avoided or deferred distribution 
10operation and maintenance costs, distribution voltage and 
11power quality benefits, and line loss reductions. 
12    "Threshold date" means the date 2 years after the 
13effective date of this amendatory Act of the 104th General 
14Assembly December 31, 2024 or the date on which the utility's 
15tariff or tariffs authorized by Section 16-107.9 setting the 
16new compensation values established under subsection (e) take 
17effect, whichever is later.
18    (b) An electric utility that serves more than 200,000 
19customers in the State shall file a petition with the 
20Commission requesting approval of the utility's tariff to 
21provide a rebate to the owner or operator of distributed 
22generation, including third-party owned systems, that meets 
23the following criteria:
24        (1) has a nameplate generating capacity no greater 
25    than 5,000 kilowatts and is primarily used to offset a 
26    customer's electricity load;
 
 
10400SB0025ham002- 600 -LRB104 07069 AAS 28576 a

1        (2) is located on the customer's side of the billing 
2    meter and for the customer's own use;
3        (3) is interconnected to electric distribution 
4    facilities owned by the electric utility under rules 
5    adopted by the Commission by means of one or more 
6    inverters or smart inverters required by this Section, as 
7    applicable.
8    For purposes of this Section, "distributed generation" 
9shall satisfy the definition of distributed renewable energy 
10generation device set forth in Section 1-10 of the Illinois 
11Power Agency Act to the extent such definition is consistent 
12with the requirements of this Section. 
13    In addition, any new photovoltaic distributed generation 
14that is installed after June 1, 2017 (the effective date of 
15Public Act 99-906) must be installed by a qualified person, as 
16defined by subsection (i) of Section 1-56 of the Illinois 
17Power Agency Act. 
18    The tariff shall include a base rebate that compensates 
19distributed generation for the system-wide grid services 
20associated with distributed generation and, after the 
21proceeding described in subsection (e) of this Section, an 
22additional payment or payments for any the additive services 
23identified by the Commission under Section 16-107.9. The 
24distributed generation and storage tariff shall provide that 
25the smart inverter or smart inverters associated with the 
26distributed generation shall provide autonomous response to 
 
 
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1grid conditions through its default settings as approved by 
2the Commission. Default settings may not be changed after the 
3execution of the interconnection agreement except by mutual 
4agreement between the utility and the owner or operator of the 
5distributed generation. Nothing in this Section shall negate 
6or supersede Institute of Electrical and Electronics Engineers 
7equipment standards or other similar standards or 
8requirements. The tariff shall not limit the ability of the 
9smart inverter or smart inverters or other distributed energy 
10resource to provide wholesale market products such as 
11regulation, demand response, or other services, or limit the 
12ability of the owner of the smart inverter or the other 
13distributed energy resource to receive compensation for 
14providing those wholesale market products or services.
15    (b-5) Within 30 days after the effective date of this 
16amendatory Act of the 102nd General Assembly, each electric 
17public utility with 3,000,000 or more retail customers shall 
18file a tariff with the Commission that further compensates any 
19retail customer that installs or has installed photovoltaic 
20facilities paired with energy storage facilities on or 
21adjacent to its premises for the benefits the facilities 
22provide to the distribution grid. The tariff shall provide 
23that, in addition to the other rebates identified in this 
24Section, the electric utility shall rebate to such retail 
25customer (i) the previously incurred and future costs of 
26installing interconnection facilities and related 
 
 
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1infrastructure to enable full participation in the PJM 
2Interconnection, LLC or its successor organization frequency 
3regulation market; and (ii) all wholesale demand charges 
4incurred after the effective date of this amendatory Act of 
5the 102nd General Assembly. The Commission shall approve, or 
6approve with modification, the tariff within 120 days after 
7the utility's filing. 
8    To be eligible for a rebate described in this subsection 
9(b-5), the owner or operator of the distributed generation 
10shall provide proof of participation in the frequency 
11regulation market. Upon providing proof of participation, the 
12retail customer shall be entitled to a rebate equal to the cost 
13of the interconnection facilities paid to ComEd, regardless of 
14whether the retail customer would have incurred the 
15interconnection costs in the absence of participating in the 
16frequency regulation market, plus the cost of software, 
17telecommunications hardware, and telemetry paid to enable 
18communication with PJM for purposes of participating in the 
19frequency regulation market. A utility providing rebates 
20described in this subsection (b-5) shall be entitled to 
21recover the costs of the rebates as provided for in subsection 
22(h) of this Section. To the extent the electric utility's 
23tariff shall be modified to comply with this subsection (b-5), 
24it shall file a revised tariff with the Commission within 120 
25days after the effective date of this amendatory Act of the 
26104th General Assembly, and the Commission shall approve, or 
 
 
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1approve with modification, the tariff within 240 days after 
2the utility's filing.    
3    (c) The proposed tariff authorized by subsection (b) of 
4this Section shall include the following participation terms 
5for rebates to be applied under this Section for distributed 
6generation that satisfies the criteria set forth in subsection 
7(b) of this Section:
8        (1) The owner or operator of distributed generation or 
9    distributed storage that services customers not eligible 
10    for net metering under subsection (d), (d-5), or (e) of 
11    Section 16-107.5 of this Act may apply for a rebate as 
12    provided for in this Section. The Until the threshold 
13    date, the value of the rebate shall be $250 per kilowatt of 
14    nameplate generating capacity, measured as nominal DC 
15    power output, of that customer's distributed generation. 
16    To the extent the distributed generation also has an 
17    associated energy storage, then until the threshold date 
18    for systems other than community renewable generation 
19    projects paired with an energy storage system, the energy 
20    storage system shall be separately compensated with a base    
21    rebate of $250 per kilowatt-hour of nameplate capacity. To 
22    the extent that a community renewable generation project 
23    is paired with an energy storage system, the energy 
24    storage system shall be separately compensated with a 
25    rebate of $250 per kilowatt-hour of nameplate capacity.    
26    Any distributed generation device that is compensated for 
 
 
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1    storage in this subsection (1) after the effective date of 
2    this amendatory Act of the 104th General Assembly before 
3    the threshold date shall participate in one or more 
4    programs authorized by paragraph (1) of subsection (e). 
5    Compensation determined through the Multi-Year Integrated 
6    Grid Planning process that are designed to meet peak 
7    reduction and flexibility. After the threshold date, the 
8    value of the base rebate and additional compensation for 
9    any additive services shall be as determined by the 
10    Commission in the proceeding described in Section 16-107.9    
11    subsection (e) of this Section, provided that the value of 
12    the base rebate for system-wide grid services shall not be 
13    lower than $250 per kilowatt of nameplate generating 
14    capacity of distributed generation or community renewable 
15    generation project. To the extent that an electric 
16    utility's tariffs are inconsistent with the requirements 
17    of this paragraph (1) as modified by this amendatory Act 
18    of the 104th General Assembly, the electric utility shall, 
19    within 60 days after the effective date of this amendatory 
20    Act of the 104th General Assembly, file modified tariffs 
21    consistent with the requirements of this paragraph (1).    
22        (2) The owner or operator of distributed generation 
23    that, before the threshold date, would have been eligible 
24    for net metering under subsection (d), (d-5), or (e) of 
25    Section 16-107.5 of this Act and that has not previously 
26    received a distributed generation rebate, may apply for a 
 
 
10400SB0025ham002- 605 -LRB104 07069 AAS 28576 a

1    rebate as provided for in this Section. Until December 31, 
2    2029 the threshold date, the value of the base rebate 
3    shall be $300 per kilowatt of nameplate generating 
4    capacity, measured as nominal DC power output, of the 
5    distributed generation. On or after January 1, 2030, the 
6    value of the base rebate shall be $250 per kilowatt of 
7    nameplate generating capacity, measured as nominal DC 
8    power output, of the distributed generation. The owner or 
9    operator of distributed generation that, before the 
10    threshold date, is eligible for net metering under 
11    subsection (d), (d-5), or (e) of Section 16-107.5 of this 
12    Act may apply for a base rebate for an associated energy 
13    storage device behind the same retail customer meter as 
14    the distributed generation, regardless of whether the 
15    distributed generation applies for a rebate for the 
16    distributed generation device. An The energy storage 
17    system, whether or not paired with distributed generation,    
18    shall be separately compensated at a base payment of $300 
19    per kilowatt-hour of nameplate capacity until the 
20    threshold date. Any distributed generation device that is 
21    compensated for storage in this subsection (2) has the 
22    option to before the threshold date shall participate in 
23    either an a peak time rebate program, hourly pricing 
24    program, or time-of-use rate program and any distributed 
25    generation device that is compensated for storage in this 
26    subsection (2) after the effective date of this amendatory 
 
 
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1    Act of the 104th General Assembly shall participate in a 
2    scheduled dispatch program set forth in paragraph (1) of 
3    subsection (e) when it becomes available offered by the 
4    applicable electric utility. Compensation After the 
5    threshold date, the value of the base rebate and 
6    additional compensation for any additive services or other 
7    programs shall be as determined by the Commission in the 
8    proceeding described in Section 16-107.9 subsection (e) of 
9    this Section, provided that, prior to December 31, 2029, 
10    the value of the base rebate for system-wide services 
11    shall not be lower than $300 per kilowatt of nameplate 
12    generating capacity of distributed generation, after which 
13    it shall not be lower than $250 per kilowatt of nameplate 
14    capacity. The eligibility of energy storage devices that 
15    are interconnected behind the same retail customer meter 
16    as the distributed generation shall not be limited to 
17    energy storage devices interconnected after the effective 
18    date of this amendatory Act of the 103rd General Assembly. 
19    To the extent that an electric utility's tariffs are 
20    inconsistent with the requirements of this paragraph (2) 
21    as modified by this amendatory Act of the 104th General 
22    Assembly this amendatory Act of the 103rd General 
23    Assembly, such electric utility shall, within 60 30 days, 
24    file modified tariffs consistent with the requirements of 
25    this paragraph (2). 
26        (3) Upon approval of a rebate application submitted 
 
 
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1    under this subsection (c), the retail customer shall no 
2    longer be entitled to receive any delivery service credits 
3    for the excess electricity generated by its facility and 
4    shall be subject to the provisions of subsection (n) of 
5    Section 16-107.5 of this Act unless the owner or operator 
6    receives a rebate only for an energy storage device and 
7    not for the distributed generation device.
8        (4) To be eligible for a rebate described in this 
9    subsection (c), the owner or operator of the distributed 
10    generation must have a smart inverter installed and in 
11    operation on the distributed generation.
12        (5) The owner or operator of any distributed 
13    generation or distributed storage system whose electric 
14    service has not been declared competitive under Section 
15    16-113 as of July 1, 2011 or the owner or operator of a 
16    community renewable generation project participating in 
17    the Adjustable Block Program as a community-driven 
18    community solar project as defined in item (v) of 
19    subparagraph (1) of paragraph (K) of subsection (c) of 
20    Section 1-75 of the Illinois Power Agency Act and that has 
21    an interconnection agreement dated after the effective 
22    date of this amendatory Act of the 104th General Assembly 
23    shall be eligible for an additional payment or payments to 
24    the applicable rebate under paragraphs (1) or (2) of this 
25    subsection (c) in an amount set by tariff and approved by 
26    the Commission if located in an equity investment eligible 
 
 
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1    community, as defined in Section 1-10 of the Illinois 
2    Power Agency Act, at the time the interconnection 
3    agreement is signed.    
4    (d) The Commission shall review the proposed tariff 
5authorized by subsection (b) of this Section and may make 
6changes to the tariff that are consistent with this Section 
7and with the Commission's authority under Article IX of this 
8Act, subject to notice and hearing. Following notice and 
9hearing, the Commission shall issue an order approving, or 
10approving with modification, such tariff no later than 240 
11days after the utility files its tariff. Upon the effective 
12date of this amendatory Act of the 102nd General Assembly, an 
13electric utility shall file a petition with the Commission to 
14amend and update any existing tariffs to comply with 
15subsections (b) and (c). 
16    (e) By no later than June 30, 2026 June 30, 2023, the 
17Commission shall establish a scheduled dispatch virtual power 
18plant program in which customers that own or operate an energy 
19storage system that receive a rebate for the distributed 
20storage portion under paragraphs (1) and (2) of subsection (c) 
21are required to participate open an independent, statewide 
22investigation into the value of, and compensation for, 
23distributed energy resources. The Commission shall conduct the 
24investigation, but may arrange for experts or consultants 
25independent of the utilities and selected by the Commission to 
26assist with the investigation. The cost of the investigation 
 
 
10400SB0025ham002- 609 -LRB104 07069 AAS 28576 a

1shall be shared by the utilities filing tariffs under 
2subsection (b) of this Section but may be recovered as an 
3expense through normal ratemaking procedures.
4        (1) The scheduled dispatch virtual power plant program 
5    shall require an enrollment period of 5 years and require 
6    each participating system to commit to dispatch each 
7    weekday during the months of June, July, August, and 
8    September from 4 p.m. to 6 p.m. for systems interconnected 
9    behind the meter of a retail customer and from 4 p.m. to 7 
10    p.m. for systems interconnected on the distribution system 
11    of an electric utility and not behind the meter of a retail 
12    customer. Upon petition by the applicable electric utility 
13    or on its own motion, the Commission may approve different 
14    dispatch schedules provided that dispatch events do not 
15    exceed 80 days and shall not exceed 2 hours for systems 
16    interconnected behind the meter of a retail customer or 3 
17    hours for systems interconnected on the distribution 
18    system of an electric utility and not behind the meter of a 
19    retail customer. The Commission shall ensure that the 
20    investigation includes, at minimum, diverse sets of 
21    stakeholders; a review of best practices in calculating 
22    the value of distributed energy resource benefits; a 
23    review of the full value of the distributed energy 
24    resources and the manner in which each component of that 
25    value is or is not otherwise compensated; and assessments 
26    of how the value of distributed energy resources may 
 
 
10400SB0025ham002- 610 -LRB104 07069 AAS 28576 a

1    evolve based on the present and future technological 
2    capabilities of distributed energy resources and based on 
3    present and future grid needs.    
4        (2) The scheduled dispatch virtual power plant program 
5    shall be open to all customer classes with eligible energy 
6    storage systems and shall measure performance based on 
7    combined export of paired resources if the eligible device 
8    is inverter-based renewables paired with storage through 
9    at least December 31, 2030 and until such time as the 
10    Commission approves and the utility implements a tariff 
11    under subsection (d) of Section 16-107.9 of this Act, at 
12    which time such customers shall be transitioned to that 
13    tariff in a manner prescribed in the tariff. The scheduled 
14    dispatch virtual power plant program shall be required for 
15    all community renewable generation projects paired with an 
16    energy storage system without regard to the threshold 
17    date. The Commission's final order concluding this 
18    investigation shall establish an annual process and 
19    formula for the compensation of distributed generation and 
20    energy storage systems, and an initial set of inputs for 
21    that formula. The Commission's final order concluding this 
22    investigation shall establish base rebates that compensate 
23    distributed generation, community renewable generation 
24    projects and energy storage systems for the system-wide 
25    grid services that they provide. Those base rebate values 
26    shall be consistent across the state, and shall not vary 
 
 
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1    by customer, customer class, customer location, or any 
2    other variable. With respect to rebates for distributed 
3    generation or community renewable generation projects, 
4    that rebate shall not be lower than $250 per kilowatt of 
5    nameplate generating capacity of the distributed 
6    generation or community renewable generation project. The 
7    Commission's final order concluding this proceeding shall 
8    also direct the utilities to update the formula, on an 
9    annual basis, with inputs derived from their integrated 
10    grid plans developed pursuant to Section 16-105.17. The 
11    base rebate shall be updated annually based on the annual 
12    updates to the formula inputs, but, with respect to 
13    rebates for distributed generation or community renewable 
14    generation projects, shall be no lower than $250 per 
15    kilowatt of nameplate generating capacity of the 
16    distributed generation or community renewable generation 
17    project.
18        (3) Compensation shall be set by the Commission but 
19    shall not be less than $10 per kilowatt of average 
20    dispatch during identified hours, paid to enrolled 
21    customers or project owners at end of program year. For 
22    distributed generation interconnected to an electric 
23    utility's distribution system and not behind the meter of 
24    a retail customer, dispatch to determine compensation 
25    shall be measured at point of interconnection. For 
26    distributed generation and storage interconnected behind 
 
 
10400SB0025ham002- 612 -LRB104 07069 AAS 28576 a

1    the meter of a retail customer, dispatch to determine 
2    compensation shall be measured at the inverter connected 
3    to the storage device. The Commission shall also 
4    determine, as a part of its investigation under this 
5    subsection, whether distributed energy resources can 
6    provide any additive services. Those additive services may 
7    include services that are provided through 
8    utility-controlled responses to grid conditions. If the 
9    Commission determines that distributed energy resources 
10    can provide additive grid services, the Commission shall 
11    determine the terms and conditions for the operation and 
12    compensation of those services. That compensation shall be 
13    above and beyond the base rebate that the distributed 
14    energy generation, community renewable generation project 
15    and energy storage system receives. Compensation for 
16    additive services may vary by location, time, performance 
17    characteristics, technology types, or other variables.
18        (4) No later than June 1, 2026, each public utility 
19    shall file an initial scheduled dispatch virtual power 
20    plant tariff. The Commission shall approve, or approve 
21    with modifications, the initial scheduled dispatch virtual 
22    power plant tariff for each utility not later than June 
23    30, 2026. The Commission shall ensure that compensation 
24    for distributed energy resources, including base rebates 
25    and any payments for additive services, shall reflect all 
26    reasonably known and measurable values of the distributed 
 
 
10400SB0025ham002- 613 -LRB104 07069 AAS 28576 a

1    generation over its full expected useful life. 
2    Compensation for additive services shall reflect, but 
3    shall not be limited to, any geographic, time-based, 
4    performance-based, and other benefits of distributed 
5    generation, as well as the present and future 
6    technological capabilities of distributed energy resources 
7    and present and future grid needs.
8        (5) The Commission, by its own motion or by petition 
9    by an electric utility, may establish other additive 
10    services programs in addition to the virtual power plant 
11    program under Section 16-107.9. Nothing in this Section is 
12    intended to preempt or delay the implementation of other 
13    utility programs for devices that are not a part of the 
14    scheduled dispatch virtual power plant program that the 
15    Commission or utility may propose or require. The 
16    Commission shall consider the electric utility's 
17    integrated grid plan developed pursuant to Section 
18    16-105.17 of this Act to help identify the value of 
19    distributed energy resources for the purpose of 
20    calculating the compensation described in this subsection.    
21        (6) No later than December 31, 2028, the utilities 
22    shall file with the Commission a report that includes 
23    information on the following: (A) the number of 
24    participants in the scheduled dispatch program; (B) 
25    impacts to energy supply prices and wholesale market 
26    activities; (C) impacts on distribution system investments 
 
 
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1    and planning; and (D) any potential pathways by which the 
2    virtual power plan program described in Section 16-107.9 
3    may be designed to capture wholesale market value through 
4    participation in the wholesale market and apply that 
5    wholesale market revenue to reduce utility distribution or 
6    electric supply rates for customers. The Commission shall 
7    determine additional compensation for distributed energy 
8    resources that creates savings and value on the 
9    distribution system by being co-located or in close 
10    proximity to electric vehicle charging infrastructure in 
11    use by medium-duty and heavy-duty vehicles, primarily 
12    serving environmental justice communities, as outlined in 
13    the utility integrated grid planning process under Section 
14    16-105.17 of this Act.    
15    No later than 60 days after the Commission enters its 
16final order under this subsection (e), each utility shall file 
17its updated tariff or tariffs in compliance with the order, 
18including new tariffs for the recovery of costs incurred under 
19this subsection (e) that shall provide for volumetric-based 
20cost recovery, and the Commission shall approve, or approve 
21with modification, the tariff or tariffs within 240 days after 
22the utility's filing.    
23    (f) Notwithstanding any provision of this Act to the 
24contrary, the owner or operator of a community renewable 
25generation project as defined in Section 1-10 of the Illinois 
26Power Agency Act whether or not a paired energy storage system 
 
 
10400SB0025ham002- 615 -LRB104 07069 AAS 28576 a

1or the owner or operator of an energy storage system that is 
2eligible for net metering under subsection (l-10) of Section 
316-107.5 shall also be eligible to apply for the rebate 
4described in this Section. The owner or operator of the 
5community renewable generation project whether or not a paired 
6energy storage system or the owner or operator of an energy 
7storage system that is eligible for net metering under 
8subsection (l-10) of Section 16-107.5 may apply for a rebate 
9only if the owner or operator, or previous owner or operator, 
10of the community renewable generation project whether or not a 
11paired energy storage system or the owner or operator of an 
12energy storage system that is eligible for net metering under 
13subsection (l-10) of Section 16-107.5 has not already 
14submitted an application, and, regardless of whether the 
15subscriber is a residential or non-residential customer, may 
16be allowed the amount identified in paragraph (1) of 
17subsection (c) applicable on the date that the application is 
18submitted.
19    (g) The owner of a distributed storage system, whether or 
20not paired with distributed generation, the distributed 
21generation or community renewable generation project may apply 
22for the rebate or rebates approved under this Section at the 
23time of execution of an interconnection agreement with the 
24distribution utility and shall receive the value available at 
25that time of execution of the interconnection agreement, 
26provided the project reaches mechanical completion within 24 
 
 
10400SB0025ham002- 616 -LRB104 07069 AAS 28576 a

1months after execution of the interconnection agreement. If 
2the project has not reached mechanical completion within 24 
3months after execution, the owner may reapply for the rebate 
4or rebates approved under this Section available at the time 
5of application and shall receive the value available at the 
6time of application. The utility shall issue the rebate no 
7later than 60 days after the project is energized. In the event 
8the application is incomplete or the utility is otherwise 
9unable to calculate the payment based on the information 
10provided by the owner, the utility shall issue the payment no 
11later than 60 days after the application is complete or all 
12requested information is received.
13    (h) An electric utility shall recover from its retail 
14customers all of the costs of the rebates made under a tariff 
15or tariffs approved under subsection (d) of this Section, 
16including, but not limited to, the value of the rebates and all 
17costs incurred by the utility to comply with and implement 
18subsections (b), (b-5), and (c), and (e) of this Section, but 
19not including costs incurred by the utility to comply with and 
20implement subsection (e) of this Section, consistent with the 
21following provisions:
22        (1) The utility shall defer the full amount of its 
23    costs as a regulatory asset. The total costs deferred as a 
24    regulatory asset shall be amortized over a 15-year period. 
25    The unamortized balance shall be recognized as of December 
26    31 for a given year. The utility shall also earn a return 
 
 
10400SB0025ham002- 617 -LRB104 07069 AAS 28576 a

1    on the total of the unamortized balance of the regulatory 
2    assets, less any deferred taxes related to the unamortized 
3    balance, at an annual rate equal to the utility's weighted 
4    average cost of capital that includes, based on a year-end 
5    capital structure, the utility's actual cost of debt for 
6    the applicable calendar year and a cost of equity, which 
7    shall be equal to the baseline cost of equity approved by 
8    the Commission for the utility's electric distribution 
9    rates case effective during the applicable year, whether 
10    those rates are set pursuant to Section 9-201, 
11    subparagraph (B) of paragraph (3) of subsection (d) of 
12    Section 16-108.18, or any successor electric distribution 
13    ratemaking paradigm calculated as the sum of (i) the 
14    average for the applicable calendar year of the monthly 
15    average yields of 30-year U.S. Treasury bonds published by 
16    the Board of Governors of the Federal Reserve System in 
17    its weekly H.15 Statistical Release or successor 
18    publication; and (ii) 580 basis points, including a 
19    revenue conversion factor calculated to recover or refund 
20    all additional income taxes that may be payable or 
21    receivable as a result of that return.
22        When an electric utility creates a regulatory asset 
23    under the provisions of this paragraph (1) of subsection 
24    (h), the costs are recovered over a period during which 
25    customers also receive a benefit, which is in the public 
26    interest. Accordingly, it is the intent of the General 
 
 
10400SB0025ham002- 618 -LRB104 07069 AAS 28576 a

1    Assembly that an electric utility that elects to create a 
2    regulatory asset under the provisions of this paragraph 
3    (1) shall recover all of the associated costs, including, 
4    but not limited to, its cost of capital as set forth in 
5    this paragraph (1). After the Commission has approved the 
6    prudence and reasonableness of the costs that comprise the 
7    regulatory asset, the electric utility shall be permitted 
8    to recover all such costs, and the value and 
9    recoverability through rates of the associated regulatory 
10    asset shall not be limited, altered, impaired, or reduced. 
11    To enable the financing of the incremental capital 
12    expenditures, including regulatory assets, for electric 
13    utilities that serve less than 3,000,000 retail customers 
14    but more than 500,000 retail customers in the State, the 
15    utility's actual year-end capital structure that includes 
16    a common equity ratio, excluding goodwill, of up to and 
17    including 50% of the total capital structure shall be 
18    deemed reasonable and used to set rates.
19        (2) The utility, at its election, may recover all of 
20    the costs as part of a filing for a general increase in 
21    rates under Article IX of this Act, as part of an annual 
22    filing to update a performance-based formula rate under 
23    Section 16-108.18 subsection (d) of Section 16-108.5 of 
24    this Act, or through an automatic adjustment clause 
25    tariff, provided that nothing in this paragraph (2) 
26    permits the double recovery of such costs from customers. 
 
 
10400SB0025ham002- 619 -LRB104 07069 AAS 28576 a

1    If the utility elects to recover the costs it incurs under 
2    subsections (b), (b-5), and (c), and (e) through an 
3    automatic adjustment clause tariff, the utility may file 
4    its proposed tariff together with the tariff it files 
5    under subsection (b) of this Section or at a later time. 
6    The proposed tariff shall provide for an annual 
7    reconciliation, less any deferred taxes related to the 
8    reconciliation, with interest at an annual rate of return 
9    equal to the utility's weighted average cost of capital as 
10    calculated under paragraph (1) of this subsection (h), 
11    including a revenue conversion factor calculated to 
12    recover or refund all additional income taxes that may be 
13    payable or receivable as a result of that return, of the 
14    revenue requirement reflected in rates for each calendar 
15    year, beginning with the calendar year in which the 
16    utility files its automatic adjustment clause tariff under 
17    this subsection (h), with what the revenue requirement 
18    would have been had the actual cost information for the 
19    applicable calendar year been available at the filing 
20    date. The Commission shall review the proposed tariff and 
21    may make changes to the tariff that are consistent with 
22    this Section and with the Commission's authority under 
23    Article IX of this Act, subject to notice and hearing. 
24    Following notice and hearing, the Commission shall issue 
25    an order approving, or approving with modification, such 
26    tariff no later than 240 days after the utility files its 
 
 
10400SB0025ham002- 620 -LRB104 07069 AAS 28576 a

1    tariff.
2    (i) (Blank). An electric utility shall recover from its 
3retail customers, on a volumetric basis, all of the costs of 
4the rebates made under a tariff or tariffs placed into effect 
5under subsection (e) of this Section, including, but not 
6limited to, the value of the rebates and all costs incurred by 
7the utility to comply with and implement subsection (e) of 
8this Section, consistent with the following provisions:
9        (1) The utility may defer a portion of its costs as a 
10    regulatory asset. The Commission shall determine the 
11    portion that may be appropriately deferred as a regulatory 
12    asset. Factors that the Commission shall consider in 
13    determining the portion of costs that shall be deferred as 
14    a regulatory asset include, but are not limited to: (i) 
15    whether and the extent to which a cost effectively 
16    deferred or avoided other distribution system operating 
17    costs or capital expenditures; (ii) the extent to which a 
18    cost provides environmental benefits; (iii) the extent to 
19    which a cost improves system reliability or resilience; 
20    (iv) the electric utility's distribution system plan 
21    developed pursuant to Section 16-105.17 of this Act; (v) 
22    the extent to which a cost advances equity principles; and 
23    (vi) such other factors as the Commission deems 
24    appropriate. The remainder of costs shall be deemed an 
25    operating expense and shall be recoverable if found 
26    prudent and reasonable by the Commission.    
 
 
10400SB0025ham002- 621 -LRB104 07069 AAS 28576 a

1        The total costs deferred as a regulatory asset shall 
2    be amortized over a 15-year period. The unamortized 
3    balance shall be recognized as of December 31 for a given 
4    year. The utility shall also earn a return on the total of 
5    the unamortized balance of the regulatory assets, less any 
6    deferred taxes related to the unamortized balance, at an 
7    annual rate equal to the utility's weighted average cost 
8    of capital that includes, based on a year-end capital 
9    structure, the utility's actual cost of debt for the 
10    applicable calendar year and a cost of equity, which shall 
11    be calculated as the sum of: (I) the average for the 
12    applicable calendar year of the monthly average yields of 
13    30-year U.S. Treasury bonds published by the Board of 
14    Governors of the Federal Reserve System in its weekly H.15 
15    Statistical Release or successor publication; and (II) 580 
16    basis points, including a revenue conversion factor 
17    calculated to recover or refund all additional income 
18    taxes that may be payable or receivable as a result of that 
19    return.
20        (2) The utility may recover all of the costs through 
21    an automatic adjustment clause tariff, on a volumetric 
22    basis. The utility may file its proposed cost-recovery 
23    tariff together with the tariff it files under subsection 
24    (e) of this Section or at a later time. The proposed tariff 
25    shall provide for an annual reconciliation, less any 
26    deferred taxes related to the reconciliation, with 
 
 
10400SB0025ham002- 622 -LRB104 07069 AAS 28576 a

1    interest at an annual rate of return equal to the 
2    utility's weighted average cost of capital as calculated 
3    under paragraph (1) of this subsection (i), including a 
4    revenue conversion factor calculated to recover or refund 
5    all additional income taxes that may be payable or 
6    receivable as a result of that return, of the revenue 
7    requirement reflected in rates for each calendar year, 
8    beginning with the calendar year in which the utility 
9    files its automatic adjustment clause tariff under this 
10    subsection (i), with what the revenue requirement would 
11    have been had the actual cost information for the 
12    applicable calendar year been available at the filing 
13    date. The Commission shall review the proposed tariff and 
14    may make changes to the tariff that are consistent with 
15    this Section and with the Commission's authority under 
16    Article IX of this Act, subject to notice and hearing. 
17    Following notice and hearing, the Commission shall issue 
18    an order approving, or approving with modification, such 
19    tariff no later than 240 days after the utility files its 
20    tariff.    
21    (j) No later than 90 days after the Commission enters an 
22order, or order on rehearing, whichever is later, approving an 
23electric utility's proposed tariff under this Section, the 
24electric utility shall provide notice of the availability of 
25rebates under this Section.
26    (k) No later than January 1, 2030, the utilities shall 
 
 
10400SB0025ham002- 623 -LRB104 07069 AAS 28576 a

1file with the Commission a report that includes:
2        (1) the number and geographic distribution of 
3    participants receiving rebates pursuant to this Section;
4        (2) impacts to energy supply prices and wholesale 
5    market activities;
6        (3) impacts on distribution system investments and 
7    planning; and
8        (4) any other values deemed relevant by the 
9    Commission.
10    (l) Upon petition by the applicable electric utility or on 
11its own motion, the Commission may adjust rebate levels for 
12new customers and make other appropriate changes to the rebate 
13program in a manner that is consistent with the State's clean 
14energy goals and the public interest.    
15(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22; 
16103-1066, eff. 2-20-25.)
 
17    (220 ILCS 5/16-107.8 new)
18    Sec. 16-107.8. Time-of-use pricing.
19    (a) The General Assembly finds that market-based 
20time-of-use rates and pricing plans can reduce costs and help 
21the State achieve its energy policy goals by improving load 
22shape, encouraging energy conservation, and shifting usage 
23away from periods where fossil fuels are used. By providing 
24consumers information relating the costs of service to the 
25time of energy usage, time-of-use rates can help consumers 
 
 
10400SB0025ham002- 624 -LRB104 07069 AAS 28576 a

1reduce energy bills by using electricity when it is less 
2costly.
3    (b) An electric utility shall offer at least one 
4market-based rate option for eligible retail customers, 
5including, but not limited to, customers participating in net 
6electricity metering under the terms of Section 16-107.5, who 
7choose to take power and energy supply service from the 
8utility. The provisions of Section 16-107.5 notwithstanding, 
9energy credits for net-metering customers shall be valued at 
10the same price per kilowatt-hour as the price per 
11kilowatt-hour that the electric service provider would charge 
12for kilowatt-hour energy sales during the same hourly 
13time-of-use period. The utility shall file its time-of-use 
14rate tariff no later than 120 days after the effective date of 
15this amendatory Act of the 104th General Assembly. The tariff 
16or tariffs shall be subject to the following requirements:
17        (1) If more than one tariff is proposed, at least one 
18    tariff shall include at least the following 3 time blocks:
19            (A) a peak time block of consecutive hours best 
20        reflecting the average consecutive highest system 
21        power and energy use per hour in a calendar day;
22            (B) an off-peak time block, which reflects the 
23        next highest system power and energy demands in a 
24        calendar day; and
25            (C) a super-off-peak time block, defined as all 
26        other hours in a calendar day.
 
 
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1            Time blocks shall reflect the hour and weekday for 
2        which the costs of services outlined in paragraphs (2) 
3        and (3) of this subsection (b) are charged.
4        (2) The tariff or tariffs shall describe the 
5    methodology for determining the prices for each time block 
6    using the applicable average zonal and capacity prices of 
7    the PJM Interconnection, LLC (PJM) and the Midcontinent 
8    Independent System Operator (MISO) and describe the manner 
9    in which customers who elect time-of-use pricing will be 
10    provided with the time blocks, associated block pricing, 
11    and day-ahead energy prices. Costs for electric capacity 
12    shall be determined in a manner that recovers the capacity 
13    obligation costs incurred by the electric utility.
14        (3) The time-of-use rate shall include the costs of 
15    transmission services and the charges for network 
16    integration transmission service, transmission 
17    enhancement, and locational reliability, as these terms 
18    are defined in the PJM and MISO Open Access Transmission 
19    Tariffs and manuals. If the Open Access Transmission 
20    Tariff or the manuals subsequently rename those terms, the 
21    services reflected under those terms shall continue to be 
22    included in the time-of-use rate described in this 
23    paragraph (3).
24        (4) Adjustments to the charges set by the tariff may 
25    be made on a monthly basis and adjustments to the time 
26    blocks may be made on an annual basis. A utility shall 
 
 
10400SB0025ham002- 626 -LRB104 07069 AAS 28576 a

1    submit to the Commission, through a supplemental 
2    information sheet, a tariff schedule. Customers shall be 
3    provided at least 2 weeks advance notice of any changes to 
4    charges or time blocks.
5        (5) A purchased energy adjustment shall be calculated 
6    to fully recover costs to supply power and energy. A 
7    utility shall procure power and energy in the applicable 
8    day-ahead market.
9    (c) The Commission shall approve or approve with 
10modifications the tariff or tariffs after notice and hearing. 
11A proceeding under this subsection (c) may not exceed 240 days 
12in length.
13    (d) An electric utility shall submit an annual report to 
14the Commission no later than April 1 of each year that 
15describes the operation and results of the rate option, 
16including information concerning the number and types of 
17customers using the rate option, changes in customers' energy 
18use patterns, an assessment of the value of the rate option to 
19both participants and nonparticipants, and recommendations 
20concerning modification of the rate option and the tariff or 
21tariffs filed under this Section. The report shall be made 
22available to the public on the Commission's website.
23    (e) Once a tariff or tariffs has been in effect, the 
24Commission may, upon complaint, petition, or its own 
25initiative, open a proceeding to investigate whether changes 
26or modifications, consistent with the requirements of this 
 
 
10400SB0025ham002- 627 -LRB104 07069 AAS 28576 a

1Section, to the tariff or tariffs, rate option administration, 
2or any other rate option element is necessary to achieve the 
3goals described in subsection (a). Such a proceeding may not 
4last more than 180 days from the date upon which the 
5investigation was opened.
6    (f) An electric utility shall be entitled to recover 
7prudent and reasonable costs incurred in complying with this 
8Section from its eligible retail customers.
9    (g) An electric utility's tariff or tariffs filed under 
10this Section shall be subject to the provisions of Article IX 
11as long as such provisions do not conflict with this Section.
12    (h) This Section does not apply to an electric utility 
13that provides service to 100,000 or fewer customers.    
 
14    (220 ILCS 5/16-107.9 new)
15    Sec. 16-107.9. Virtual power plant program.
16    (a) As used in this Section:
17    "Aggregator" means a third-party entity that participates 
18in the program, other than the electric utility or its 
19affiliate, that (i) represents and aggregates the load of 
20participating customers who collectively have the ability to 
21deploy 100 kilowatts or more of deployment of eligible devices 
22and (ii) is responsible for performance of the aggregation in 
23the program.
24    "Battery" means a behind-the-meter energy storage device 
25and associated equipment that operate together to fulfill 
 
 
10400SB0025ham002- 628 -LRB104 07069 AAS 28576 a

1program requirements.
2    "Commission" means the Illinois Commerce Commission.
3    "Customer" means an active electric service account holder 
4of a utility.
5    "Direct participant" means a customer that enrolls in the 
6program directly with the utility, rather than participating 
7in the program through an aggregator.
8    "Distributed energy resource" has the meaning set forth in 
9Section 16-107.6.
10    "Distributed energy resources management system" means a 
11platform that may be used by distribution system operators or 
12utilities to integrate grid resources, such as distributed 
13energy resources, into system operations.
14    "Eligible device" means a customer or third party-owned 
15distributed energy resource that satisfies the requirements 
16for participation in the program as specified in the relevant 
17program rider. "Eligible device" also means any device that 
18can be controlled to respond to pricing, provide services, 
19including decrease peak electricity demand or shift demand 
20from peak to off-peak periods, or inject power to the grid. 
21"Eligible device" includes, but is not limited to, 
22behind-the-meter energy storage systems, smart thermostats, 
23electric vehicle batteries, including fleets, and distributed 
24renewable energy devices paired with one or more energy 
25storage systems.
26    "Emergency event" means an event called by the utility 
 
 
10400SB0025ham002- 629 -LRB104 07069 AAS 28576 a

1with fewer than 24 hours notice.
2    "Energy storage system" has the meaning set forth in 
3subsection (a) of Section 16-107.6.
4    "Enrolled customer" means a customer that participates in 
5the program through either an aggregator or as a direct 
6participant.
7    "Enrolled device" means an enrolled customer's eligible 
8device, as specified in the relevant tariff.
9    "Enterprise distributed energy resources management 
10system" means a platform operated by the electric utility that 
11interfaces with a grid-edge distributed energy resources 
12management system to integrate distributed energy resources 
13into utility electric system operations.
14    "Grid-edge distributed energy resources management system" 
15means a platform owned by a party other than the electric 
16utility that may be used to integrate distributed energy 
17resources.
18    "Grid event" means a grid condition for which the utility 
19schedules or remotely dispatches enrolled devices to respond 
20to, as specified in the grid service opportunities for each 
21tariff.
22    "Grid service" means a capacity, energy, or ancillary 
23service that supports grid operations.
24    "Participating customer" means an aggregator or a direct 
25retail customer, as defined in Section 16-102, with one or 
26more eligible devices.
 
 
10400SB0025ham002- 630 -LRB104 07069 AAS 28576 a

1    "Performance payment" means a payment made to the 
2participant based on the performance of an enrolled device 
3providing a grid service during a grid event.
4    "Performance payment rate" means the compensation rate 
5paid to participants for providing a particular grid service 
6during a grid event.
7    "Smart inverter" has the meaning set forth in subsection 
8(a) of Section 16-107.6.
9    "Upfront payment" means a one-time payment made at the 
10time of enrollment.
11    "Virtual power plant" means an aggregation of 
12behind-the-meter distributed energy resources operated in 
13coordination to provide one or more grid services.
14    (b) The General Assembly finds that:
15        (1) virtual power plants are dynamic load management 
16    and energy supply resources that can support grid 
17    operations, reduce ratepayer costs, and achieve other 
18    important public policy goals;
19        (2) virtual power plants can reduce demand for grid 
20    supplied electricity during peak periods, shift 
21    electricity consumption out of peak periods, make 
22    renewable energy generated during off-peak periods 
23    available for use during peak periods, supply energy to 
24    the grid at desired times, provide frequency regulation, 
25    voltage support, and other ancillary services, reduce 
26    strain on the distribution system, manage localized peaks, 
 
 
10400SB0025ham002- 631 -LRB104 07069 AAS 28576 a

1    improve system resiliency and reliability, and provide 
2    other grid services;
3        (3) virtual power plants can facilitate and optimize 
4    the utilization of electrical generation from wind and 
5    solar energy to help utilities increase hosting capacity 
6    and integrate more renewable energy resources;
7        (4) virtual power plants can reduce costs to 
8    ratepayers by utilizing customer-sited resources to 
9    provide grid services, avoiding or reducing reliance on 
10    fossil-fuel fired peaker plants, avoiding or deferring the 
11    need to construct new and more costly grid scale 
12    resources, optimizing the use of existing assets, and 
13    avoiding or deferring distribution and transmission system 
14    upgrades and other grid investments;
15        (5) virtual power plants can promote equity by 
16    reducing costs for all ratepayers, expanding access to 
17    distributed energy resources among low-income and 
18    moderate-income customers through improved distributed 
19    energy resource finance ability, and providing other 
20    important co-benefits, including reduction in emissions of 
21    greenhouse gases and other pollutants, especially in 
22    environmental justice and other disadvantaged communities 
23    that host fossil fuel generation plants;
24        (6) the United States Department of Energy estimates 
25    that the United States could deploy 80 to 160 gigawatts of 
26    virtual power plants by 2030, a tripling of current 
 
 
10400SB0025ham002- 632 -LRB104 07069 AAS 28576 a

1    levels, to support the rapid electrification of vehicles 
2    and homes and provide on the order of $10,000,000,000 in 
3    ratepayer savings annually. The deployment of virtual 
4    power plants can provide energy cost savings and other 
5    benefits to the people of Illinois;
6        (7) there are significant barriers to deployment and 
7    operation of virtual power plants, including the need for 
8    statutory and regulatory guidance and support, greater 
9    consistency in virtual power plant programs across 
10    regulatory jurisdictions, and for utility commitments to 
11    incorporate the use of virtual power plants into system 
12    operations and long-term resource planning;
13        (8) it is in the public interest to advance customer 
14    choice and leverage the expertise of private, non-utility 
15    entities to advance innovation and implement 
16    cost-effective clean energy solutions; and
17        (9) the policy of Illinois shall be to maximize the 
18    use of virtual power plants comprised of customer-owned 
19    and third party-owned distributed energy resources to 
20    deliver system services and other benefits through utility 
21    administered virtual power plant programs in accordance 
22    with the provisions of this amendatory Act of the 104th 
23    General Assembly.
24    (c) No later than December 31, 2028, the Commission shall 
25approve at least one virtual power plant tariff for each 
26electric utility serving more than 300,000 customers in the 
 
 
10400SB0025ham002- 633 -LRB104 07069 AAS 28576 a

1State as of January 1, 2023. Each utility shall file a tariff 
2or tariffs for approval no later than December 31, 2027 to 
3allow retail customers in the electric utility's service areas 
4to participate in a virtual power plant program proposal 
5consistent with the provisions of this Section. The Commission 
6shall provide opportunities for stakeholders to provide input 
7on the virtual power plant programs proposed for 
8implementation by each utility, which the Commission shall 
9take into consideration in its review of each utility's 
10filing. No later than one year after the utility's filing, the 
11Commission shall approve or modify and approve each utility's 
12virtual power plant program proposal for immediate 
13implementation by the utility.
14    (d) The virtual power plant program filed under subsection 
15(c) shall be developed for implementation through a tariff 
16offering with standard terms and conditions for participation. 
17The virtual power plant program tariff shall allow for 
18customers with battery storage, non-battery storage and 
19electric vehicle technologies to enroll the devices in the 
20program through aggregators or directly with the utility. The 
21virtual power plant program tariff shall:
22        (1) provide a mechanism to incorporate existing 
23    programs, such as smart thermostat demand-response or 
24    electric vehicle charging programs currently offered by 
25    the utility, under the virtual power plant program 
26    framework;
 
 
10400SB0025ham002- 634 -LRB104 07069 AAS 28576 a

1        (2) provide grid services opportunities for each 
2    eligible technology that customers and aggregators may 
3    provide, which shall include, at minimum, reducing the 
4    utility's applicable capacity and transmission obligations 
5    and capturing daily wholesale energy arbitrage 
6    opportunities through provision of grid services;
7        (3) provide additional functions and grid service 
8    opportunities that the Commission determines are 
9    supportive of efficient planning and operation of the 
10    electrical grid, including:
11            (A) minimizing the use of fossil fuels at peak 
12        times;
13            (B) local peak demand reductions;
14            (C) locational value;
15            (D) the avoidance or deferral of local 
16        transmission or distribution upgrades or capacity 
17        expansion;
18            (E) voltage support and other ancillary services; 
19        and
20            (F) emergency grid services;
21        (4) provide operational parameters, which shall 
22    include, at a minimum:
23            (A) minimum and maximum numbers of grid events for 
24        which the utility may require dispatch from the 
25        enrolled distributed energy resources;
26            (B) months of the year that grid events may occur;
 
 
10400SB0025ham002- 635 -LRB104 07069 AAS 28576 a

1            (C) days of the week that grid events may occur;
2            (D) times of day that grid events may occur;
3            (E) maximum duration of grid events; and
4            (F) minimum day-ahead advance notification 
5        requirement of grid events, except for emergency 
6        events, as applicable;
7        (5) include provisions for aggregators to participate 
8    in the virtual power plant program, participate in the 
9    utility's distributed energy resource management system as 
10    available, automatically enroll and manage their 
11    customers' participation, receive dispatch signals and 
12    other communications from the utility, deliver performance 
13    measurement and verification data to the utility, and 
14    receive virtual power plant program payments directly from 
15    the utility;
16        (6) include provisions that provide a standardized 
17    process for any eligible aggregator to enroll in the 
18    program and authorize the eligible aggregators to manage 
19    individual customer device participation without 
20    additional authorizations from the utility;
21        (7) include provisions that allow a participating 
22    customer with multiple eligible devices to enroll the 
23    technologies either directly without an aggregator or 
24    through one or more aggregators in applicable programs 
25    under the tariff approved under this Section, provided 
26    that no particular device is accounted for more than once;
 
 
10400SB0025ham002- 636 -LRB104 07069 AAS 28576 a

1        (8) include provisions for direct participant 
2    customers to participate with the utility's distributed 
3    energy resource management system as available, receive 
4    dispatch signals and other communications from the 
5    utility, deliver performance measurement and verification 
6    data to the utility, and receive virtual power plant 
7    program payments directly from the utility. Any provisions 
8    implementing this subpart that necessitate the 
9    installation of equipment to enable direct participation 
10    via the utility shall apply to customers who elect to 
11    participate as a direct participant and shall not be 
12    required of customers who participate via an aggregator or 
13    to customers who do not participate in the virtual power 
14    plant program;
15        (9) provide for measurement and verification of 
16    battery non-battery, and electric vehicle technologies 
17    performance directly at the device without the requirement 
18    for the installation of an additional meter;
19        (10) include upfront payment or performance payment 
20    compensation mechanisms for the peak reduction service, as 
21    well as for non-battery and electric vehicle technologies 
22    as the Commission deems appropriate. The performance 
23    payment shall be based on the average capacity provided 
24    during grid events. The Commission shall approve 
25    additional compensation mechanisms as it determines 
26    appropriate for other grid services provided under the 
 
 
10400SB0025ham002- 637 -LRB104 07069 AAS 28576 a

1    battery, non-battery and electric vehicle riders. The 
2    virtual power plant program shall not assess penalties for 
3    non-performance; provided, however, that the Commission 
4    may approve reasonable mechanisms to disenroll customers 
5    for continued non-performance;
6        (11) enable low-to-moderate income customers, 
7    community-driven community solar projects, and customers 
8    whose electric service has not been declared competitive 
9    pursuant to Section 16-113 as of July 1, 2011 located in 
10    equity investment eligible investment communities to 
11    receive a higher upfront enrollment payment. The 
12    Commission shall coordinate with State energy officials 
13    and departments to make funding from federal programs and 
14    such other sources as may be available for use in 
15    providing higher upfront payments to customers classes as 
16    may be approved by the Commission in accordance with this 
17    subsection;
18        (12) provide that the performance payment rate 
19    applicable at the time of enrollment shall be for 5 years, 
20    after which time the participant may reenroll at the then 
21    applicable performance payment rate for an additional 
22    5-year term;
23        (13) provide for a transition of customers from the 
24    scheduled dispatch program described in Section 16-107.6 
25    to the virtual power plant program; and
26        (14) allow enrolled customers to participate in other 
 
 
10400SB0025ham002- 638 -LRB104 07069 AAS 28576 a

1    applicable interconnection tariffs and grid service 
2    programs outside the virtual power plant program, so long 
3    as it does not result in double-counting of benefits for 
4    the same grid services.
5    (e) The Commission may adopt other reasonable requirements 
6for participation consistent with this subsection, provided 
7that collateral from an aggregator shall not be required for 
8participation.
9    (f) The utility may contract with a third party-owned 
10distributed energy resource management system provider to 
11assist with program implementation; however, implementation 
12shall not be delayed due to the lack of utility-owned 
13distributed energy resource management system capabilities or 
14third party-owned distributed energy resource management 
15system capabilities.
16    (g) The utility shall not send or receive dispatch signals 
17directly to or from any participating customer represented by 
18an aggregator for an event under the virtual power plant 
19program described in this Section.
20    (h) Participating aggregators shall have capabilities to 
21receive event signals from utilities or utility-contracted 
22distributed energy resources management system providers.
23    (i) Utilities shall recover reasonably and prudently 
24incurred costs to facilitate the virtual power plant program 
25approved under subsection (c), including, but not limited to, 
26distributed energy resource management systems provider and 
 
 
10400SB0025ham002- 639 -LRB104 07069 AAS 28576 a

1other service contract costs, operations and maintenance 
2expenses, information technology costs, and other costs, 
3expenses, and investments that the Commission finds necessary 
4and prudent for the development and implementation of the 
5program. The utility shall recover the cost of virtual power 
6plant program upfront payments and performance payments and 
7such other payments made to participants through the tariff 
8filed pursuant to subsection (h) of Section 16-107.6.
9    (j) No later than January 31 of each year, each utility 
10shall file an annual report that includes, but is not limited 
11to:
12        (1) the total capacity enrolled in each program rider 
13    developed in accordance with the requirements of Section, 
14    broken down by technology type, customer class, and 
15    aggregator and direct participant status for each grid 
16    service opportunity offered in the prior calendar year;
17        (2) recommendations to increase participation in the 
18    virtual power plant program; and
19        (3) any other information that the Commission may 
20    require.
21    (k) Each utility shall amend existing tariffs and 
22procedures that limit the ability of customers to participate 
23in providing grid services under the program, such as 
24limitations on charging energy storage devices with grid 
25energy or exporting energy to the grid from battery discharge.
26    (l) The tariffs approved by the Commission shall not 
 
 
10400SB0025ham002- 640 -LRB104 07069 AAS 28576 a

1reflect any additional charges, fees, or insurance 
2requirements imposed on those owning or operating 
3demand-response technologies beyond those imposed on similarly 
4situated customers that do not own or operate demand-response 
5technologies.    
6    (m) As a condition of participating in the programs 
7described in this Section, prior to enrollment of a customer 
8by an aggregator, the aggregator shall disclose the following:
9        (1) the payments, expressed as an amount or a formula, 
10    to be provided to the customer;
11        (2) between the aggregator and customer, who is 
12    responsible for paying penalties or fees; and
13        (3) between the aggregator and customer, who is 
14    responsible for posting collateral, if required.
15    Any tariff authorized by this Section shall incorporate 
16the requirements under this subsection and shall require the 
17electric utility to establish a complaint and Commission 
18notification process and, on order of the Commission, suspend 
19any aggregator repeatedly or egregiously violating such 
20requirements.    
 
21    (220 ILCS 5/16-108)
22    Sec. 16-108. Recovery of costs associated with the 
23provision of delivery and other services.
24    (a) An electric utility shall file a delivery services 
25tariff with the Commission at least 210 days prior to the date 
 
 
10400SB0025ham002- 641 -LRB104 07069 AAS 28576 a

1that it is required to begin offering such services pursuant 
2to this Act. An electric utility shall provide the components 
3of delivery services that are subject to the jurisdiction of 
4the Federal Energy Regulatory Commission at the same prices, 
5terms and conditions set forth in its applicable tariff as 
6approved or allowed into effect by that Commission. The 
7Commission shall otherwise have the authority pursuant to 
8Article IX to review, approve, and modify the prices, terms 
9and conditions of those components of delivery services not 
10subject to the jurisdiction of the Federal Energy Regulatory 
11Commission, including the authority to determine the extent to 
12which such delivery services should be offered on an unbundled 
13basis. In making any such determination the Commission shall 
14consider, at a minimum, the effect of additional unbundling on 
15(i) the objective of just and reasonable rates, (ii) electric 
16utility employees, and (iii) the development of competitive 
17markets for electric energy services in Illinois.
18    (b) The Commission shall enter an order approving, or 
19approving as modified, the delivery services tariff no later 
20than 30 days prior to the date on which the electric utility 
21must commence offering such services. The Commission may 
22subsequently modify such tariff pursuant to this Act.
23    (c) The electric utility's tariffs shall define the 
24classes of its customers for purposes of delivery services 
25charges. Delivery services shall be priced and made available 
26to all retail customers electing delivery services in each 
 
 
10400SB0025ham002- 642 -LRB104 07069 AAS 28576 a

1such class on a nondiscriminatory basis regardless of whether 
2the retail customer chooses the electric utility, an affiliate 
3of the electric utility, or another entity as its supplier of 
4electric power and energy. Charges for delivery services shall 
5be cost based, and shall allow the electric utility to recover 
6the costs of providing delivery services through its charges 
7to its delivery service customers that use the facilities and 
8services associated with such costs. Such costs shall include 
9the costs of owning, operating and maintaining transmission 
10and distribution facilities. The Commission shall also be 
11authorized to consider whether, and if so to what extent, the 
12following costs are appropriately included in the electric 
13utility's delivery services rates: (i) the costs of that 
14portion of generation facilities used for the production and 
15absorption of reactive power in order that retail customers 
16located in the electric utility's service area can receive 
17electric power and energy from suppliers other than the 
18electric utility, and (ii) the costs associated with the use 
19and redispatch of generation facilities to mitigate 
20constraints on the transmission or distribution system in 
21order that retail customers located in the electric utility's 
22service area can receive electric power and energy from 
23suppliers other than the electric utility. Nothing in this 
24subsection shall be construed as directing the Commission to 
25allocate any of the costs described in (i) or (ii) that are 
26found to be appropriately included in the electric utility's 
 
 
10400SB0025ham002- 643 -LRB104 07069 AAS 28576 a

1delivery services rates to any particular customer group or 
2geographic area in setting delivery services rates.
3    (d) The Commission shall establish charges, terms and 
4conditions for delivery services that are just and reasonable 
5and shall take into account customer impacts when establishing 
6such charges. In establishing charges, terms and conditions 
7for delivery services, the Commission shall take into account 
8voltage level differences. A retail customer shall have the 
9option to request to purchase electric service at any delivery 
10service voltage reasonably and technically feasible from the 
11electric facilities serving that customer's premises provided 
12that there are no significant adverse impacts upon system 
13reliability or system efficiency. A retail customer shall also 
14have the option to request to purchase electric service at any 
15point of delivery that is reasonably and technically feasible 
16provided that there are no significant adverse impacts on 
17system reliability or efficiency. Such requests shall not be 
18unreasonably denied.
19    (e) Electric utilities shall recover the costs of 
20installing, operating or maintaining facilities for the 
21particular benefit of one or more delivery services customers, 
22including without limitation any costs incurred in complying 
23with a customer's request to be served at a different voltage 
24level, directly from the retail customer or customers for 
25whose benefit the costs were incurred, to the extent such 
26costs are not recovered through the charges referred to in 
 
 
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1subsections (c) and (d) of this Section.
2    (f) An electric utility shall be entitled but not required 
3to implement transition charges in conjunction with the 
4offering of delivery services pursuant to Section 16-104. If 
5an electric utility implements transition charges, it shall 
6implement such charges for all delivery services customers and 
7for all customers described in subsection (h), but shall not 
8implement transition charges for power and energy that a 
9retail customer takes from cogeneration or self-generation 
10facilities located on that retail customer's premises, if such 
11facilities meet the following criteria:    
12        (i) the cogeneration or self-generation facilities 
13    serve a single retail customer and are located on that 
14    retail customer's premises (for purposes of this 
15    subparagraph and subparagraph (ii), an industrial or 
16    manufacturing retail customer and a third party contractor 
17    that is served by such industrial or manufacturing 
18    customer through such retail customer's own electrical 
19    distribution facilities under the circumstances described 
20    in subsection (vi) of the definition of "alternative 
21    retail electric supplier" set forth in Section 16-102, 
22    shall be considered a single retail customer);    
23        (ii) the cogeneration or self-generation facilities 
24    either (A) are sized pursuant to generally accepted 
25    engineering standards for the retail customer's electrical 
26    load at that premises (taking into account standby or 
 
 
10400SB0025ham002- 645 -LRB104 07069 AAS 28576 a

1    other reliability considerations related to that retail 
2    customer's operations at that site) or (B) if the facility 
3    is a cogeneration facility located on the retail 
4    customer's premises, the retail customer is the thermal 
5    host for that facility and the facility has been designed 
6    to meet that retail customer's thermal energy requirements 
7    resulting in electrical output beyond that retail 
8    customer's electrical demand at that premises, comply with 
9    the operating and efficiency standards applicable to 
10    "qualifying facilities" specified in title 18 Code of 
11    Federal Regulations Section 292.205 as in effect on the 
12    effective date of this amendatory Act of 1999;    
13        (iii) the retail customer on whose premises the 
14    facilities are located either has an exclusive right to 
15    receive, and corresponding obligation to pay for, all of 
16    the electrical capacity of the facility, or in the case of 
17    a cogeneration facility that has been designed to meet the 
18    retail customer's thermal energy requirements at that 
19    premises, an identified amount of the electrical capacity 
20    of the facility, over a minimum 5-year period; and    
21        (iv) if the cogeneration facility is sized for the 
22    retail customer's thermal load at that premises but 
23    exceeds the electrical load, any sales of excess power or 
24    energy are made only at wholesale, are subject to the 
25    jurisdiction of the Federal Energy Regulatory Commission, 
26    and are not for the purpose of circumventing the 
 
 
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1    provisions of this subsection (f).
2If a generation facility located at a retail customer's 
3premises does not meet the above criteria, an electric utility 
4implementing transition charges shall implement a transition 
5charge until December 31, 2006 for any power and energy taken 
6by such retail customer from such facility as if such power and 
7energy had been delivered by the electric utility. Provided, 
8however, that an industrial retail customer that is taking 
9power from a generation facility that does not meet the above 
10criteria but that is located on such customer's premises will 
11not be subject to a transition charge for the power and energy 
12taken by such retail customer from such generation facility if 
13the facility does not serve any other retail customer and 
14either was installed on behalf of the customer and for its own 
15use prior to January 1, 1997, or is both predominantly fueled 
16by byproducts of such customer's manufacturing process at such 
17premises and sells or offers an average of 300 megawatts or 
18more of electricity produced from such generation facility 
19into the wholesale market. Such charges shall be calculated as 
20provided in Section 16-102, and shall be collected on each 
21kilowatt-hour delivered under a delivery services tariff to a 
22retail customer from the date the customer first takes 
23delivery services until December 31, 2006 except as provided 
24in subsection (h) of this Section. Provided, however, that an 
25electric utility, other than an electric utility providing 
26service to at least 1,000,000 customers in this State on 
 
 
10400SB0025ham002- 647 -LRB104 07069 AAS 28576 a

1January 1, 1999, shall be entitled to petition for entry of an 
2order by the Commission authorizing the electric utility to 
3implement transition charges for an additional period ending 
4no later than December 31, 2008. The electric utility shall 
5file its petition with supporting evidence no earlier than 16 
6months, and no later than 12 months, prior to December 31, 
72006. The Commission shall hold a hearing on the electric 
8utility's petition and shall enter its order no later than 8 
9months after the petition is filed. The Commission shall 
10determine whether and to what extent the electric utility 
11shall be authorized to implement transition charges for an 
12additional period. The Commission may authorize the electric 
13utility to implement transition charges for some or all of the 
14additional period, and shall determine the mitigation factors 
15to be used in implementing such transition charges; provided, 
16that the Commission shall not authorize mitigation factors 
17less than 110% of those in effect during the 12 months ended 
18December 31, 2006. In making its determination, the Commission 
19shall consider the following factors: the necessity to 
20implement transition charges for an additional period in order 
21to maintain the financial integrity of the electric utility; 
22the prudence of the electric utility's actions in reducing its 
23costs since the effective date of this amendatory Act of 1997; 
24the ability of the electric utility to provide safe, adequate 
25and reliable service to retail customers in its service area; 
26and the impact on competition of allowing the electric utility 
 
 
10400SB0025ham002- 648 -LRB104 07069 AAS 28576 a

1to implement transition charges for the additional period.
2    (g) The electric utility shall file tariffs that establish 
3the transition charges to be paid by each class of customers to 
4the electric utility in conjunction with the provision of 
5delivery services. The electric utility's tariffs shall define 
6the classes of its customers for purposes of calculating 
7transition charges. The electric utility's tariffs shall 
8provide for the calculation of transition charges on a 
9customer-specific basis for any retail customer whose average 
10monthly maximum electrical demand on the electric utility's 
11system during the 6 months with the customer's highest monthly 
12maximum electrical demands equals or exceeds 3.0 megawatts for 
13electric utilities having more than 1,000,000 customers, and 
14for other electric utilities for any customer that has an 
15average monthly maximum electrical demand on the electric 
16utility's system of one megawatt or more, and (A) for which 
17there exists data on the customer's usage during the 3 years 
18preceding the date that the customer became eligible to take 
19delivery services, or (B) for which there does not exist data 
20on the customer's usage during the 3 years preceding the date 
21that the customer became eligible to take delivery services, 
22if in the electric utility's reasonable judgment there exists 
23comparable usage information or a sufficient basis to develop 
24such information, and further provided that the electric 
25utility can require customers for which an individual 
26calculation is made to sign contracts that set forth the 
 
 
10400SB0025ham002- 649 -LRB104 07069 AAS 28576 a

1transition charges to be paid by the customer to the electric 
2utility pursuant to the tariff.
3    (h) An electric utility shall also be entitled to file 
4tariffs that allow it to collect transition charges from 
5retail customers in the electric utility's service area that 
6do not take delivery services but that take electric power or 
7energy from an alternative retail electric supplier or from an 
8electric utility other than the electric utility in whose 
9service area the customer is located. Such charges shall be 
10calculated, in accordance with the definition of transition 
11charges in Section 16-102, for the period of time that the 
12customer would be obligated to pay transition charges if it 
13were taking delivery services, except that no deduction for 
14delivery services revenues shall be made in such calculation, 
15and usage data from the customer's class shall be used where 
16historical usage data is not available for the individual 
17customer. The customer shall be obligated to pay such charges 
18on a lump sum basis on or before the date on which the customer 
19commences to take service from the alternative retail electric 
20supplier or other electric utility, provided, that the 
21electric utility in whose service area the customer is located 
22shall offer the customer the option of signing a contract 
23pursuant to which the customer pays such charges ratably over 
24the period in which the charges would otherwise have applied.
25    (i) An electric utility shall be entitled to add to the 
26bills of delivery services customers charges pursuant to 
 
 
10400SB0025ham002- 650 -LRB104 07069 AAS 28576 a

1Sections 9-221, 9-222 (except as provided in Section 9-222.1), 
2and Section 16-114 of this Act, Section 5-5 of the Electricity 
3Infrastructure Maintenance Fee Law, Section 6-5 of the 
4Renewable Energy, Energy Efficiency, and Coal Resources 
5Development Law of 1997, and Section 13 of the Energy 
6Assistance Act.
7    (i-5) An electric utility required to impose the Coal to 
8Solar and Energy Storage Initiative Charge provided for in 
9subsection (c-5) of Section 1-75 of the Illinois Power Agency 
10Act shall add such charge to the bills of its delivery services 
11customers pursuant to the terms of a tariff conforming to the 
12requirements of subsection (c-5) of Section 1-75 of the 
13Illinois Power Agency Act and this subsection (i-5) and filed 
14with and approved by the Commission. The electric utility 
15shall file its proposed tariff with the Commission on or 
16before July 1, 2022 to be effective, after review and approval 
17or modification by the Commission, beginning January 1, 2023. 
18On or before December 1, 2022, the Commission shall review the 
19electric utility's proposed tariff, including by conducting a 
20docketed proceeding if deemed necessary by the Commission, and 
21shall approve the proposed tariff or direct the electric 
22utility to make modifications the Commission finds necessary 
23for the tariff to conform to the requirements of subsection 
24(c-5) of Section 1-75 of the Illinois Power Agency Act and this 
25subsection (i-5). The electric utility's tariff shall provide 
26for imposition of the Coal to Solar and Energy Storage 
 
 
10400SB0025ham002- 651 -LRB104 07069 AAS 28576 a

1Initiative Charge on a per-kilowatthour basis to all 
2kilowatthours delivered by the electric utility to its 
3delivery services customers. The tariff shall provide for the 
4calculation of the Coal to Solar and Energy Storage Initiative 
5Charge to be in effect for the year beginning January 1, 2023 
6and each year beginning January 1 thereafter, sufficient to 
7collect the electric utility's estimated payment obligations 
8for the delivery year beginning the following June 1 under 
9contracts for purchase of renewable energy credits entered 
10into pursuant to subsection (c-5) of Section 1-75 of the 
11Illinois Power Agency Act and the obligations of the 
12Department of Commerce and Economic Opportunity, or any 
13successor department or agency, which for purposes of this 
14subsection (i-5) shall be referred to as the Department, to 
15make grant payments during such delivery year from the Coal to 
16Solar and Energy Storage Initiative Fund pursuant to grant 
17contracts entered into pursuant to subsection (c-5) of Section 
181-75 of the Illinois Power Agency Act, and using the electric 
19utility's kilowatthour deliveries to its delivery services 
20customers during the delivery year ended May 31 of the 
21preceding calendar year. On or before November 1 of each year 
22beginning November 1, 2022, the Department shall notify the 
23electric utilities of the amount of the Department's estimated 
24obligations for grant payments during the delivery year 
25beginning the following June 1 pursuant to grant contracts 
26entered into pursuant to subsection (c-5) of Section 1-75 of 
 
 
10400SB0025ham002- 652 -LRB104 07069 AAS 28576 a

1the Illinois Power Agency Act; and each electric utility shall 
2incorporate in the calculation of its Coal to Solar and Energy 
3Storage Initiative Charge the fractional portion of the 
4Department's estimated obligations equal to the electric 
5utility's kilowatthour deliveries to its delivery services 
6customers in the delivery year ended the preceding May 31 
7divided by the aggregate deliveries of both electric utilities 
8to delivery services customers in such delivery year. The 
9electric utility shall remit on a monthly basis to the State 
10Treasurer, for deposit in the Coal to Solar and Energy Storage 
11Initiative Fund provided for in subsection (c-5) of Section 
121-75 of the Illinois Power Agency Act, the electric utility's 
13collections of the Coal to Solar and Energy Storage Initiative 
14Charge estimated to be needed by the Department for grant 
15payments pursuant to grant contracts entered into pursuant to 
16subsection (c-5) of Section 1-75 of the Illinois Power Agency 
17Act. The initial charge under the electric utility's tariff 
18shall be effective for kilowatthours delivered beginning 
19January 1, 2023, and thereafter shall be revised to be 
20effective January 1, 2024 and each January 1 thereafter, based 
21on the payment obligations for the delivery year beginning the 
22following June 1. The tariff shall provide for the electric 
23utility to make an annual filing with the Commission on or 
24before November 15 of each year, beginning in 2023, setting 
25forth the Coal to Solar and Energy Storage Initiative Charge 
26to be in effect for the year beginning the following January 1. 
 
 
10400SB0025ham002- 653 -LRB104 07069 AAS 28576 a

1The electric utility's tariff shall also provide that the 
2electric utility shall make a filing with the Commission on or 
3before August 1 of each year beginning in 2024 setting forth a 
4reconciliation, for the delivery year ended the preceding May 
531, of the electric utility's collections of the Coal to Solar 
6and Energy Storage Initiative Charge against actual payments 
7for renewable energy credits pursuant to contracts entered 
8into, and the actual grant payments by the Department pursuant 
9to grant contracts entered into, pursuant to subsection (c-5) 
10of Section 1-75 of the Illinois Power Agency Act. The tariff 
11shall provide that any excess or shortfall of collections to 
12payments shall be deducted from or added to, on a 
13per-kilowatthour basis, the Coal to Solar and Energy Storage 
14Initiative Charge, over the 6-month period beginning October 1 
15of that calendar year. 
16    (j) If a retail customer that obtains electric power and 
17energy from cogeneration or self-generation facilities 
18installed for its own use on or before January 1, 1997, 
19subsequently takes service from an alternative retail electric 
20supplier or an electric utility other than the electric 
21utility in whose service area the customer is located for any 
22portion of the customer's electric power and energy 
23requirements formerly obtained from those facilities 
24(including that amount purchased from the utility in lieu of 
25such generation and not as standby power purchases, under a 
26cogeneration displacement tariff in effect as of the effective 
 
 
10400SB0025ham002- 654 -LRB104 07069 AAS 28576 a

1date of this amendatory Act of 1997), the transition charges 
2otherwise applicable pursuant to subsections (f), (g), or (h) 
3of this Section shall not be applicable in any year to that 
4portion of the customer's electric power and energy 
5requirements formerly obtained from those facilities, 
6provided, that for purposes of this subsection (j), such 
7portion shall not exceed the average number of kilowatt-hours 
8per year obtained from the cogeneration or self-generation 
9facilities during the 3 years prior to the date on which the 
10customer became eligible for delivery services, except as 
11provided in subsection (f) of Section 16-110.
12    (k) The electric utility shall be entitled to recover 
13through tariffed charges all of the costs associated with the 
14purchase of zero emission credits from zero emission 
15facilities to meet the requirements of subsection (d-5) of 
16Section 1-75 of the Illinois Power Agency Act and all of the 
17costs associated with the purchase of carbon mitigation 
18credits from carbon-free energy resources to meet the 
19requirements of subsection (d-10) of Section 1-75 of the 
20Illinois Power Agency Act. Such costs shall include the costs 
21of procuring the zero emission credits and carbon mitigation 
22credits from carbon-free energy resources, as well as the 
23reasonable costs that the utility incurs as part of the 
24procurement processes and to implement and comply with plans 
25and processes approved by the Commission under subsections 
26(d-5) and (d-10). The costs shall be allocated across all 
 
 
10400SB0025ham002- 655 -LRB104 07069 AAS 28576 a

1retail customers through a single, uniform cents per 
2kilowatt-hour charge applicable to all retail customers, which 
3shall appear as a separate line item on each customer's bill. 
4The electric utility shall be entitled to recover through 
5tariffed charges approved by the Commission all of the prudent 
6and reasonable costs associated with energy storage resources 
7procurements to meet the energy storage system portfolio 
8standard of subsection (d-20) of Section 1-75 of the Illinois 
9Power Agency Act. Such costs shall include the contract costs 
10for the energy storage system resources and the prudent and 
11reasonable costs that the utility incurs as part of the 
12procurement processes and in implementing and complying with 
13plans and processes approved by the Commission under 
14subsection (d-20). The costs associated with the purchase of 
15energy storage system resources shall be allocated across all 
16retail customers in proportion to the amount of energy storage 
17system resources the utility procures for such customers 
18through a single, uniform cents per kilowatt-hour charge 
19applicable to such retail customers, which shall appear as a 
20separate line item on each customer's bill. Beginning June 1, 
212017, the electric utility shall be entitled to recover 
22through tariffed charges all of the costs associated with the 
23purchase of renewable energy resources to meet the renewable 
24energy resource standards of subsection (c) of Section 1-75 of 
25the Illinois Power Agency Act, under procurement plans as 
26approved in accordance with that Section and Section 16-111.5 
 
 
10400SB0025ham002- 656 -LRB104 07069 AAS 28576 a

1of this Act. Such costs shall include the costs of procuring 
2the renewable energy resources, as well as the reasonable 
3costs that the utility incurs as part of the procurement 
4processes and to implement and comply with plans and processes 
5approved by the Commission under such Sections. The costs 
6associated with the purchase of renewable energy resources 
7shall be allocated across all retail customers in proportion 
8to the amount of renewable energy resources the utility 
9procures for such customers through a single, uniform cents 
10per kilowatt-hour charge applicable to such retail customers, 
11which shall appear as a separate line item on each such 
12customer's bill. The credits, costs, and penalties associated 
13with the self-direct renewable portfolio standard compliance 
14program described in subparagraph (R) of paragraph (1) of 
15subsection (c) of Section 1-75 of the Illinois Power Agency 
16Act shall be allocated to approved eligible self-direct 
17customers by the utility in a cents per kilowatt-hour credit, 
18cost, or penalty, which shall appear as a separate line item on 
19each such customer's bill. 
20    Notwithstanding whether the Commission has approved the 
21initial long-term renewable resources procurement plan as of 
22June 1, 2017, an electric utility shall place new tariffed 
23charges into effect beginning with the June 2017 monthly 
24billing period, to the extent practicable, to begin recovering 
25the costs of procuring renewable energy resources, as those 
26charges are calculated under the limitations described in 
 
 
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1subparagraph (E) of paragraph (1) of subsection (c) of Section 
21-75 of the Illinois Power Agency Act. Notwithstanding the 
3date on which the utility places such new tariffed charges 
4into effect, the utility shall be permitted to collect the 
5charges under such tariff as if the tariff had been in effect 
6beginning with the first day of the June 2017 monthly billing 
7period. For the delivery years commencing June 1, 2017, June 
81, 2018, June 1, 2019, and each delivery year thereafter, the 
9electric utility shall deposit into a separate interest 
10bearing account of a financial institution the monies 
11collected under the tariffed charges. Money collected from 
12customers for the procurement of renewable energy resources in 
13a given delivery year may be spent by the utility for the 
14procurement of renewable resources over any of the following 5 
15delivery years, after which unspent money shall be credited 
16back to retail customers. The electric utility shall spend all 
17money collected in earlier delivery years that has not yet 
18been returned to customers, first, before spending money 
19collected in later delivery years. Any interest earned shall 
20be credited back to retail customers under the reconciliation 
21proceeding provided for in this subsection (k), provided that 
22the electric utility shall first be reimbursed from the 
23interest for the administrative costs that it incurs to 
24administer and manage the account. Any taxes due on the funds 
25in the account, or interest earned on it, will be paid from the 
26account or, if insufficient monies are available in the 
 
 
10400SB0025ham002- 658 -LRB104 07069 AAS 28576 a

1account, from the monies collected under the tariffed charges 
2to recover the costs of procuring renewable energy resources. 
3Monies deposited in the account shall be subject to the 
4review, reconciliation, and true-up process described in this 
5subsection (k) that is applicable to the funds collected and 
6costs incurred for the procurement of renewable energy 
7resources.
8    The electric utility shall be entitled to recover all of 
9the costs identified in this subsection (k) through automatic 
10adjustment clause tariffs applicable to all of the utility's 
11retail customers that allow the electric utility to adjust its 
12tariffed charges consistent with this subsection (k). The 
13determination as to whether any excess funds were collected 
14during a given delivery year for the purchase of renewable 
15energy resources, and the crediting of any excess funds back 
16to retail customers, shall not be made until after the close of 
17the delivery year, which will ensure that the maximum amount 
18of funds is available to implement the approved long-term 
19renewable resources procurement plan during a given delivery 
20year. The amount of excess funds eligible to be credited back 
21to retail customers shall be reduced by an amount equal to the 
22payment obligations required by any contracts entered into by 
23an electric utility under contracts described in subsection 
24(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
25Illinois Power Agency Act, even if such payments have not yet 
26been made and regardless of the delivery year in which those 
 
 
10400SB0025ham002- 659 -LRB104 07069 AAS 28576 a

1payment obligations were incurred. Notwithstanding anything to 
2the contrary, including in tariffs authorized by this 
3subsection (k) in effect before the effective date of this 
4amendatory Act of the 102nd General Assembly, all unspent 
5funds as of May 31, 2021, excluding any funds credited to 
6customers during any utility billing cycle that commences 
7prior to the effective date of this amendatory Act of the 102nd 
8General Assembly, shall remain in the utility account and 
9shall on a first in, first out basis be used toward utility 
10payment obligations under contracts described in subsection 
11(b) of Section 1-56 and subsection (c) of Section 1-75 of the 
12Illinois Power Agency Act. The electric utility's collections 
13under such automatic adjustment clause tariffs to recover the 
14costs of renewable energy resources, zero emission credits 
15from zero emission facilities, energy storage resources, and 
16carbon mitigation credits from carbon-free energy resources 
17shall be subject to separate annual review, reconciliation, 
18and true-up against actual costs by the Commission under a 
19procedure that shall be specified in the electric utility's 
20automatic adjustment clause tariffs and that shall be approved 
21by the Commission in connection with its approval of such 
22tariffs. The procedure shall provide that any difference 
23between the electric utility's collections for energy storage 
24resources, zero emission credits, and carbon mitigation 
25credits under the automatic adjustment charges for an annual 
26period and the electric utility's actual costs of energy 
 
 
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1storage resources, zero emission credits from zero emission 
2facilities, and carbon mitigation credits from carbon-free 
3energy resources for that same annual period shall be refunded 
4to or collected from, as applicable, the electric utility's 
5retail customers in subsequent periods.
6    Nothing in this subsection (k) is intended to affect, 
7limit, or change the right of the electric utility to recover 
8the costs associated with the procurement of renewable energy 
9resources for periods commencing before, on, or after June 1, 
102017, as otherwise provided in the Illinois Power Agency Act. 
11    The funding available under this subsection (k), if any, 
12for the programs described under subsection (b) of Section 
131-56 of the Illinois Power Agency Act shall not reduce the 
14amount of funding for the programs described in subparagraph 
15(O) of paragraph (1) of subsection (c) of Section 1-75 of the 
16Illinois Power Agency Act. If funding is available under this 
17subsection (k) for programs described under subsection (b) of 
18Section 1-56 of the Illinois Power Agency Act, then the 
19long-term renewable resources plan shall provide for the 
20Agency to procure contracts in an amount that does not exceed 
21the funding, and the contracts approved by the Commission 
22shall be executed by the applicable utility or utilities. 
23    (l) A utility that has terminated any contract executed 
24under subsection (d-5) or (d-10) of Section 1-75 of the 
25Illinois Power Agency Act shall be entitled to recover any 
26remaining balance associated with the purchase of zero 
 
 
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1emission credits prior to such termination, and such utility 
2shall also apply a credit to its retail customer bills in the 
3event of any over-collection. 
4    (m)(1) An electric utility that recovers its costs of 
5procuring zero emission credits from zero emission facilities 
6through a cents-per-kilowatthour charge under subsection (k) 
7of this Section shall be subject to the requirements of this 
8subsection (m). Notwithstanding anything to the contrary, such 
9electric utility shall, beginning on April 30, 2018, and each 
10April 30 thereafter until April 30, 2026, calculate whether 
11any reduction must be applied to such cents-per-kilowatthour 
12charge that is paid by retail customers of the electric 
13utility that have opted out of subsections (a) through (j) of 
14Section 8-103B of this Act under subsection (l) of Section 
158-103B. Such charge shall be reduced for such customers for 
16the next delivery year commencing on June 1 based on the amount 
17necessary, if any, to limit the annual estimated average net 
18increase for the prior calendar year due to the future energy 
19investment costs to no more than 1.3% of 5.98 cents per 
20kilowatt-hour, which is the average amount paid per 
21kilowatthour for electric service during the year ending 
22December 31, 2015 by Illinois industrial retail customers, as 
23reported to the Edison Electric Institute. 
24    The calculations required by this subsection (m) shall be 
25made only once for each year, and no subsequent rate impact 
26determinations shall be made. 
 
 
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1    (2) For purposes of this Section, "future energy 
2investment costs" shall be calculated by subtracting the 
3cents-per-kilowatthour charge identified in subparagraph (A) 
4of this paragraph (2) from the sum of the 
5cents-per-kilowatthour charges identified in subparagraph (B) 
6of this paragraph (2): 
7        (A) The cents-per-kilowatthour charge identified in 
8    the electric utility's tariff placed into effect under 
9    Section 8-103 of the Public Utilities Act that, on 
10    December 1, 2016, was applicable to those retail customers 
11    that have opted out of subsections (a) through (j) of 
12    Section 8-103B of this Act under subsection (l) of Section 
13    8-103B. 
14        (B) The sum of the following cents-per-kilowatthour 
15    charges applicable to those retail customers that have 
16    opted out of subsections (a) through (j) of Section 8-103B 
17    of this Act under subsection (l) of Section 8-103B, 
18    provided that if one or more of the following charges has 
19    been in effect and applied to such customers for more than 
20    one calendar year, then each charge shall be equal to the 
21    average of the charges applied over a period that 
22    commences with the calendar year ending December 31, 2017 
23    and ends with the most recently completed calendar year 
24    prior to the calculation required by this subsection (m): 
25            (i) the cents-per-kilowatthour charge to recover 
26        the costs incurred by the utility under subsection 
 
 
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1        (d-5) of Section 1-75 of the Illinois Power Agency 
2        Act, adjusted for any reductions required under this 
3        subsection (m); and
4            (ii) the cents-per-kilowatthour charge to recover 
5        the costs incurred by the utility under Section 
6        16-107.6 of the Public Utilities Act. 
7        If no charge was applied for a given calendar year 
8    under item (i) or (ii) of this subparagraph (B), then the 
9    value of the charge for that year shall be zero. 
10    (3) If a reduction is required by the calculation 
11performed under this subsection (m), then the amount of the 
12reduction shall be multiplied by the number of years reflected 
13in the averages calculated under subparagraph (B) of paragraph 
14(2) of this subsection (m). Such reduction shall be applied to 
15the cents-per-kilowatthour charge that is applicable to those 
16retail customers that have opted out of subsections (a) 
17through (j) of Section 8-103B of this Act under subsection (l) 
18of Section 8-103B beginning with the next delivery year 
19commencing after the date of the calculation required by this 
20subsection (m). 
21    (4) The electric utility shall file a notice with the 
22Commission on May 1 of 2018 and each May 1 thereafter until May 
231, 2026 containing the reduction, if any, which must be 
24applied for the delivery year which begins in the year of the 
25filing. The notice shall contain the calculations made 
26pursuant to this Section. By October 1 of each year beginning 
 
 
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1in 2018, each electric utility shall notify the Commission if 
2it appears, based on an estimate of the calculation required 
3in this subsection (m), that a reduction will be required in 
4the next year. 
5(Source: P.A. 102-662, eff. 9-15-21.)
 
6    (220 ILCS 5/16-108.19)
7    Sec. 16-108.19. Division of Integrated Distribution 
8Planning.
9    (a) The Commission shall employ establish the Division of 
10Integrated Distribution Planning within the Bureau of Public 
11Utilities. The Division shall be staffed by no less than 13    
12professionals, including engineers, rate analysts, 
13accountants, policy analysts, utility research and analysis 
14analysts, cybersecurity analysts, informational technology 
15specialists, and lawyers, and other personnel deemed necessary 
16and appropriate by the Executive Director to review and 
17evaluate Integrated Grid Plans, updates to Integrated Grid 
18Plans, audits, and other duties as assigned. The personnel may 
19be organized or assigned into departments, bureaus, sections, 
20or divisions as determined by the Executive Director pursuant 
21to the authority granted under this Section by the Chief of the 
22Public Utilities Bureau.
23    (b) The Division of Integrated Distribution Planning shall 
24be established by January 1, 2022. 
25(Source: P.A. 102-662, eff. 9-15-21.)
 
 
 
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1    (220 ILCS 5/16-108.30)
2    Sec. 16-108.30. Energy Transition Assistance Fund.
3    (a) The Energy Transition Assistance Fund is hereby 
4created as a special fund in the State treasury Treasury. The 
5Energy Transition Assistance Fund is authorized to receive 
6moneys collected pursuant to this Section. Subject to 
7appropriation, the Department of Commerce and Economic 
8Opportunity shall use moneys from the Energy Transition 
9Assistance Fund consistent with the purposes of this Act.
10    (b) An electric utility serving more than 500,000 
11customers in the State shall assess an energy transition 
12assistance charge on all its retail customers for the Energy 
13Transition Assistance Fund. The utility's total charge shall 
14be set based upon the value determined by the Department of 
15Commerce and Economic Opportunity pursuant to subsection (d) 
16or (e), as applicable, of Section 605-1075 of the Department 
17of Commerce and Economic Opportunity Law of the Civil 
18Administrative Code of Illinois. For each utility, the charge 
19shall be recovered through a single, uniform cents per 
20kilowatt-hour charge applicable to all retail customers. For 
21each utility, the charge shall not exceed 1.35% 1.3% of the 
22amount paid per kilowatthour by eligible retail customers 
23during the year ending May 31, 2009. Beginning January 1, 
242028, the limitation shall be increased by an additional 0.636 
25percentage points of the amount paid per kilowatt-hour by 
 
 
10400SB0025ham002- 666 -LRB104 07069 AAS 28576 a

1eligible retail customers during the year ending May 31, 2009, 
2which would collect the equivalent of the average annual 
3budget of the programs administered by the utilities under 
4Section 45 of the Electric Vehicle Act for the years 2026 
5through 2028.    
6    (c) Within 75 days of the effective date of this 
7amendatory Act of the 102nd General Assembly, each electric 
8utility serving more than 500,000 customers in the State shall 
9file with the Illinois Commerce Commission tariffs 
10incorporating the energy transition assistance charge in other 
11charges stated in such tariffs, which energy transition 
12assistance charges shall become effective no later than the 
13beginning of the first billing cycle that begins on or after 
14January 1, 2022. Each electric utility serving more than 
15500,000 customers in the State shall, prior to the beginning 
16of each calendar year starting with calendar year 2023, file 
17with the Illinois Commerce Commission tariff revisions to 
18incorporate annual revisions to the energy transition 
19assistance charge as prescribed by the Department of Commerce 
20and Economic Opportunity pursuant to Section 605-1075 of the 
21Department of Commerce and Economic Opportunity Law of the 
22Civil Administrative Code of Illinois so that such revision 
23becomes effective no later than the beginning of the first 
24billing cycle in each respective year.
25    (d) The energy transition assistance charge shall be 
26considered a charge for public utility service.
 
 
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1    (e) By the 20th day of the month following the month in 
2which the charges imposed by this Section were collected, each 
3electric utility serving more than 500,000 customers in the 
4State shall remit to Department of Revenue all moneys received 
5as payment of the energy transition assistance charge on a 
6return prescribed and furnished by the Department of Revenue 
7showing such information as the Department of Revenue may 
8reasonably require. If a customer makes a partial payment, a 
9public utility may apply such partial payments first to 
10amounts owed to the utility. No customer may be subjected to 
11disconnection of his or her utility service for failure to pay 
12the energy transition assistance charge.
13    If any payment provided for in this subsection exceeds the 
14electric utility's liabilities under this Act, as shown on an 
15original return, the Department may authorize the electric 
16utility to credit such excess payment against liability 
17subsequently to be remitted to the Department under this Act, 
18in accordance with reasonable rules adopted by the Department.
19    All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e, 
205f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13 
21of the Retailers' Occupation Tax Act that are not inconsistent 
22with this Act apply, as far as practicable, to the charge 
23imposed by this Act to the same extent as if those provisions 
24were included in this Act. References in the incorporated 
25Sections of the Retailers' Occupation Tax Act to retailers, to 
26sellers, or to persons engaged in the business of selling 
 
 
10400SB0025ham002- 668 -LRB104 07069 AAS 28576 a

1tangible personal property mean persons required to remit the 
2charge imposed under this Act.
3    (f) The Department of Revenue shall deposit into the 
4Energy Transition Assistance Fund all moneys remitted to it in 
5accordance with this Section.
6    (g) The Department of Revenue may establish such rules as 
7it deems necessary to implement this Section.
8    (h) The Department of Commerce and Economic Opportunity 
9may establish such rules as it deems necessary to implement 
10this Section. 
11(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
12    (220 ILCS 5/16-111.5)
13    Sec. 16-111.5. Provisions relating to procurement.
14    (a) An electric utility that on December 31, 2005 served 
15at least 100,000 customers in Illinois shall procure power and 
16energy for its eligible retail customers in accordance with 
17the applicable provisions set forth in Section 1-75 of the 
18Illinois Power Agency Act and this Section. Beginning with the 
19delivery year commencing on June 1, 2017, such electric 
20utility shall also procure zero emission credits from zero 
21emission facilities in accordance with the applicable 
22provisions set forth in Section 1-75 of the Illinois Power 
23Agency Act, and, for years beginning on or after June 1, 2017, 
24the utility shall procure renewable energy resources in 
25accordance with the applicable provisions set forth in Section 
 
 
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11-75 of the Illinois Power Agency Act and this Section. 
2Beginning with the delivery year commencing on June 1, 2022, 
3an electric utility serving over 3,000,000 customers shall 
4also procure carbon mitigation credits from carbon-free energy 
5resources in accordance with the applicable provisions set 
6forth in Section 1-75 of the Illinois Power Agency Act and this 
7Section. Beginning with the delivery year commencing on June 
81, 2026, an electric utility serving more than 300,000 
9customers in the State as of January 1, 2019 shall also procure 
10energy storage resources in accordance with the applicable 
11provisions of subsection (d-20) of Section 1-75 of the 
12Illinois Power Agency Act and this Section. A small 
13multi-jurisdictional electric utility that on December 31, 
142005 served less than 100,000 customers in Illinois may elect 
15to procure power and energy for all or a portion of its 
16eligible Illinois retail customers in accordance with the 
17applicable provisions set forth in this Section and Section 
181-75 of the Illinois Power Agency Act. This Section shall not 
19apply to a small multi-jurisdictional utility until such time 
20as a small multi-jurisdictional utility requests the Illinois 
21Power Agency to prepare a procurement plan for its eligible 
22retail customers. "Eligible retail customers" for the purposes 
23of this Section means those retail customers that purchase 
24power and energy from the electric utility under fixed-price 
25bundled service tariffs, other than those retail customers 
26whose service is declared or deemed competitive under Section 
 
 
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116-113 and those other customer groups specified in this 
2Section, including self-generating customers, customers 
3electing hourly pricing, or those customers who are otherwise 
4ineligible for fixed-price bundled tariff service. Except as 
5otherwise provided for in subsection (b-10), for For those 
6customers that are excluded from the procurement plan's 
7electric supply service requirements, and the utility shall 
8procure any supply requirements, including capacity, ancillary 
9services, and hourly priced energy, in the applicable markets 
10as needed to serve those customers, provided that the utility 
11may include in its procurement plan load requirements for the 
12load that is associated with those retail customers whose 
13service has been declared or deemed competitive pursuant to 
14Section 16-113 of this Act to the extent that those customers 
15are purchasing power and energy during one of the transition 
16periods identified in subsection (b) of Section 16-113 of this 
17Act. 
18    (b) A procurement plan shall be prepared for each electric 
19utility consistent with the applicable requirements of the 
20Illinois Power Agency Act and this Section. For purposes of 
21this Section, Illinois electric utilities that are affiliated 
22by virtue of a common parent company are considered to be a 
23single electric utility. Small multi-jurisdictional utilities 
24may request a procurement plan for a portion of or all of its 
25Illinois load. Each procurement plan shall analyze the 
26projected balance of supply and demand for those retail 
 
 
10400SB0025ham002- 671 -LRB104 07069 AAS 28576 a

1customers to be included in the plan's electric supply service 
2requirements over a 5-year period, with the first planning 
3year beginning on June 1 of the year following the year in 
4which the plan is filed. The plan shall specifically identify 
5the wholesale products to be procured following plan approval, 
6and shall follow all the requirements set forth in the Public 
7Utilities Act and all applicable State and federal laws, 
8statutes, rules, or regulations, as well as Commission orders. 
9Nothing in this Section precludes consideration of contracts 
10longer than 5 years and related forecast data. Unless 
11specified otherwise in this Section, in the procurement plan 
12or in the implementing tariff, any procurement occurring in 
13accordance with this plan shall be competitively bid through a 
14request for proposals process. Approval and implementation of 
15the procurement plan shall be subject to review and approval 
16by the Commission according to the provisions set forth in 
17this Section. A procurement plan shall include each of the 
18following components:
19        (1) Hourly load analysis. This analysis shall include:
20            (i) multi-year historical analysis of hourly 
21        loads;
22            (ii) switching trends and competitive retail 
23        market analysis;
24            (iii) known or projected changes to future loads; 
25        and
26            (iv) growth forecasts by customer class.
 
 
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1        (2) Analysis of the impact of any demand side and 
2    renewable energy initiatives. This analysis shall include:
3            (i) the impact of demand response programs and 
4        energy efficiency programs, both current and 
5        projected; for small multi-jurisdictional utilities, 
6        the impact of demand response and energy efficiency 
7        programs approved pursuant to Section 8-408 of this 
8        Act, both current and projected; and
9            (ii) supply side needs that are projected to be 
10        offset by purchases of renewable energy resources, if 
11        any.
12        (3) A plan for meeting the expected load requirements 
13    that will not be met through preexisting contracts. This 
14    plan shall include:
15            (i) definitions of the different Illinois retail 
16        customer classes for which supply is being purchased;
17            (ii) the proposed mix of demand-response products 
18        for which contracts will be executed during the next 
19        year. For small multi-jurisdictional electric 
20        utilities that on December 31, 2005 served fewer than 
21        100,000 customers in Illinois, these shall be defined 
22        as demand-response products offered in an energy 
23        efficiency plan approved pursuant to Section 8-408 of 
24        this Act. The cost-effective demand-response measures 
25        shall be procured whenever the cost is lower than 
26        procuring comparable capacity products, provided that 
 
 
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1        such products shall: 
2                (A) be procured by a demand-response provider 
3            from those retail customers included in the plan's 
4            electric supply service requirements;
5                (B) at least satisfy the demand-response 
6            requirements of the regional transmission 
7            organization market in which the utility's service 
8            territory is located, including, but not limited 
9            to, any applicable capacity or dispatch 
10            requirements;
11                (C) provide for customers' participation in 
12            the stream of benefits produced by the 
13            demand-response products;
14                (D) provide for reimbursement by the 
15            demand-response provider of the utility for any 
16            costs incurred as a result of the failure of the 
17            supplier of such products to perform its 
18            obligations thereunder; and
19                (E) meet the same credit requirements as apply 
20            to suppliers of capacity, in the applicable 
21            regional transmission organization market; 
22            (iii) monthly forecasted system supply 
23        requirements, including expected minimum, maximum, and 
24        average values for the planning period;
25            (iv) the proposed mix and selection of standard 
26        wholesale products for which contracts will be 
 
 
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1        executed during the next year, separately or in 
2        combination, to meet that portion of its load 
3        requirements not met through pre-existing contracts, 
4        including but not limited to monthly 5 x 16 peak period 
5        block energy, monthly off-peak wrap energy, monthly 7 
6        x 24 energy, annual 5 x 16 energy, other standardized 
7        energy or capacity products designed to provide 
8        eligible retail customer benefits from commercially 
9        deployed advanced technologies including but not 
10        limited to high voltage direct current converter 
11        stations, as such term is defined in Section 1-10 of 
12        the Illinois Power Agency Act, whether or not such 
13        product is currently available in wholesale markets, 
14        annual off-peak wrap energy, annual 7 x 24 energy, 
15        monthly capacity, annual capacity, peak load capacity 
16        obligations, capacity purchase plan, and ancillary 
17        services;
18            (v) proposed term structures for each wholesale 
19        product type included in the proposed procurement plan 
20        portfolio of products; and
21            (vi) an assessment of the price risk, load 
22        uncertainty, and other factors that are associated 
23        with the proposed procurement plan; this assessment, 
24        to the extent possible, shall include an analysis of 
25        the following factors: contract terms, time frames for 
26        securing products or services, fuel costs, weather 
 
 
10400SB0025ham002- 675 -LRB104 07069 AAS 28576 a

1        patterns, transmission costs, market conditions, and 
2        the governmental regulatory environment; the proposed 
3        procurement plan shall also identify alternatives for 
4        those portfolio measures that are identified as having 
5        significant price risk and mitigation in the form of 
6        additional retail customer and ratepayer price, 
7        reliability, and environmental benefits from 
8        standardized energy products delivered from 
9        commercially deployed advanced technologies, 
10        including, but not limited to, high voltage direct 
11        current converter stations, as such term is defined in 
12        Section 1-10 of the Illinois Power Agency Act, whether 
13        or not such product is currently available in 
14        wholesale markets.
15        (4) Proposed procedures for balancing loads. The 
16    procurement plan shall include, for load requirements 
17    included in the procurement plan, the process for (i) 
18    hourly balancing of supply and demand and (ii) the 
19    criteria for portfolio re-balancing in the event of 
20    significant shifts in load.
21        (5) Long-Term Renewable Resources Procurement Plan. 
22    The Agency shall prepare a long-term renewable resources 
23    procurement plan for the procurement of renewable energy 
24    credits under Sections 1-56 and 1-75 of the Illinois Power 
25    Agency Act for delivery beginning in the 2017 delivery 
26    year.
 
 
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1            (i) The initial long-term renewable resources 
2        procurement plan and all subsequent revisions shall be 
3        subject to review and approval by the Commission. For 
4        the purposes of this Section, "delivery year" has the 
5        same meaning as in Section 1-10 of the Illinois Power 
6        Agency Act. For purposes of this Section, "Agency" 
7        shall mean the Illinois Power Agency.
8            (ii) The long-term renewable resources planning 
9        process shall be conducted as follows:
10                (A) Electric utilities shall provide a range 
11            of load forecasts to the Illinois Power Agency 
12            within 45 days of the Agency's request for 
13            forecasts, which request shall specify the length 
14            and conditions for the forecasts including, but 
15            not limited to, the quantity of distributed 
16            generation expected to be interconnected for each 
17            year.
18                (B) The Agency shall publish for comment the 
19            initial long-term renewable resources procurement 
20            plan no later than 120 days after the effective 
21            date of this amendatory Act of the 99th General 
22            Assembly and shall review, and may revise, the 
23            plan at least every 2 years thereafter. To the 
24            extent practicable, the Agency shall review and 
25            propose any revisions to the long-term renewable 
26            energy resources procurement plan in conjunction 
 
 
10400SB0025ham002- 677 -LRB104 07069 AAS 28576 a

1            with the Agency's other planning and approval 
2            processes conducted under this Section. Plans may 
3            be released on separate dates, but the Agency 
4            shall, to the extent practicable, release both 
5            plans across a 30-day period. The initial 
6            long-term renewable resources procurement plan 
7            shall:
8                    (aa) Identify the procurement programs and 
9                competitive procurement events consistent with 
10                the applicable requirements of the Illinois 
11                Power Agency Act and shall be designed to 
12                achieve the goals set forth in subsection (c) 
13                of Section 1-75 of that Act.
14                    (bb) Include a schedule for procurements 
15                for renewable energy credits from 
16                utility-scale wind projects, utility-scale 
17                solar projects, and brownfield site 
18                photovoltaic projects consistent with 
19                subparagraph (G) of paragraph (1) of 
20                subsection (c) of Section 1-75 of the Illinois 
21                Power Agency Act.
22                    (cc) Identify the process whereby the 
23                Agency will submit to the Commission for 
24                review and approval the proposed contracts to 
25                implement the programs required by such plan.
26                If so authorized by the Commission in its 
 
 
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1            order approving the procurement plan, the 
2            procurement plan shall provide that small 
3            multi-jurisdictional electric utilities that, on 
4            December 31, 2005, served fewer than 100,000 
5            customers in Illinois shall, in lieu of serving as 
6            counterparties to contracts for the delivery of 
7            renewable energy credits, instead provide an 
8            amount equivalent to the contracts for the 
9            delivery of renewable energy credits in 
10            collections to utilities that served at least 
11            100,000 customers in Illinois as a compliance 
12            payment for the procurement of additional 
13            renewable energy credits to satisfy that small 
14            multi-jurisdictional electric utility's 
15            obligation for compliance with the goals set forth 
16            in subsection (c) of Section 1-75 of the Illinois 
17            Power Agency Act. This authorization may include 
18            the transfer of existing contract obligations.    
19                Copies of the initial long-term renewable 
20            resources procurement plan and all subsequent 
21            revisions shall be posted and made publicly 
22            available on the Agency's and Commission's 
23            websites, and copies shall also be provided to 
24            each affected electric utility. An affected 
25            utility and other interested parties shall have 45 
26            days following the date of posting to provide 
 
 
10400SB0025ham002- 679 -LRB104 07069 AAS 28576 a

1            comment to the Agency on the initial long-term 
2            renewable resources procurement plan and all 
3            subsequent revisions. All comments submitted to 
4            the Agency shall be specific, supported by data or 
5            other detailed analyses, and, if objecting to all 
6            or a portion of the procurement plan, accompanied 
7            by specific alternative wording or proposals. All 
8            comments shall be posted on the Agency's and 
9            Commission's websites. During this 45-day comment 
10            period, the Agency shall hold at least one virtual 
11            or in-person public hearing for within each 
12            utility's service area that is subject to the 
13            requirements of this paragraph (5) for the purpose 
14            of receiving public comment. Within 21 days 
15            following the end of the 45-day review period, the 
16            Agency may revise the long-term renewable 
17            resources procurement plan based on the comments 
18            received and shall file the plan with the 
19            Commission for review and approval.
20                (C) Within 14 days after the filing of the 
21            initial long-term renewable resources procurement 
22            plan or any subsequent revisions, any person 
23            objecting to the plan may file an objection with 
24            the Commission. Within 21 days after the filing of 
25            the plan, the Commission shall determine whether a 
26            hearing is necessary. The Commission shall enter 
 
 
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1            its order confirming or modifying the initial 
2            long-term renewable resources procurement plan or 
3            any subsequent revisions within 120 days after the 
4            filing of the plan by the Illinois Power Agency.
5                (D) The Commission shall approve the initial 
6            long-term renewable resources procurement plan and 
7            any subsequent revisions, including expressly the 
8            forecast used in the plan and taking into account 
9            that funding will be limited to the amount of 
10            revenues actually collected by the utilities, if 
11            the Commission determines that the plan will 
12            reasonably and prudently accomplish the 
13            requirements of Section 1-56 and subsection (c) of 
14            Section 1-75 of the Illinois Power Agency Act. The 
15            Commission shall also approve the process for the 
16            submission, review, and approval of the proposed 
17            contracts to procure renewable energy credits or 
18            implement the programs authorized by the 
19            Commission pursuant to a long-term renewable 
20            resources procurement plan approved under this 
21            Section.
22                In approving any long-term renewable resources 
23            procurement plan after the effective date of this 
24            amendatory Act of the 102nd General Assembly, the 
25            Commission shall approve or modify the Agency's 
26            proposal for minimum equity standards pursuant to 
 
 
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1            subsection (c-10) of Section 1-75 of the Illinois 
2            Power Agency Act. The Commission shall consider 
3            any analysis performed by the Agency in developing 
4            its proposal, including past performance, 
5            availability of equity eligible contractors, and 
6            availability of equity eligible persons at the 
7            time the long-term renewable resources procurement 
8            plan is approved. 
9            (iii) The Agency or third parties contracted by 
10        the Agency shall implement all programs authorized by 
11        the Commission in an approved long-term renewable 
12        resources procurement plan without further review and 
13        approval by the Commission. Third parties shall not 
14        begin implementing any programs or receive any payment 
15        under this Section until the Commission has approved 
16        the contract or contracts under the process authorized 
17        by the Commission in item (D) of subparagraph (ii) of 
18        paragraph (5) of this subsection (b) and the third 
19        party and the Agency or utility, as applicable, have 
20        executed the contract. For those renewable energy 
21        credits subject to procurement through a competitive 
22        bid process under the plan or under the initial 
23        forward procurements for wind and solar resources 
24        described in subparagraph (G) of paragraph (1) of 
25        subsection (c) of Section 1-75 of the Illinois Power 
26        Agency Act, the Agency shall follow the procurement 
 
 
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1        process specified in the provisions relating to 
2        electricity procurement in subsections (e) through (i) 
3        of this Section.
4            (iv) An electric utility shall recover its costs 
5        associated with the procurement of renewable energy 
6        credits under this Section and pursuant to subsection 
7        (c-5) of Section 1-75 of the Illinois Power Agency Act 
8        through an automatic adjustment clause tariff under 
9        subsection (k) or a tariff pursuant to subsection 
10        (i-5), as applicable, of Section 16-108 of this Act. A 
11        utility shall not be required to advance any payment 
12        or pay any amounts under this Section that exceed the 
13        actual amount of revenues collected by the utility 
14        under paragraph (6) of subsection (c) of Section 1-75 
15        of the Illinois Power Agency Act, subsection (c-5) of 
16        Section 1-75 of the Illinois Power Agency Act, and 
17        subsection (k) or subsection (i-5), as applicable, of 
18        Section 16-108 of this Act, and contracts executed 
19        under this Section shall expressly incorporate this 
20        limitation.
21            (v) For the public interest, safety, and welfare, 
22        the Agency and the Commission may adopt rules to carry 
23        out the provisions of this Section on an emergency 
24        basis immediately following the effective date of this 
25        amendatory Act of the 99th General Assembly.
26            (vi) On or before July 1 of each year, the 
 
 
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1        Commission shall hold an informal hearing for the 
2        purpose of receiving comments on the prior year's 
3        procurement process and any recommendations for 
4        change. 
5        (6) Energy Storage System Resources Procurement Plan. 
6    The Agency shall prepare an energy storage system 
7    resources procurement plan for the procurement of energy 
8    storage system resources in compliance with this Section 
9    and subsection (d-20) of Section 1-75 of the Illinois 
10    Power Agency Act.
11            (i) The initial energy storage system resources 
12        procurement plan and all subsequent revisions shall be 
13        subject to review and approval by the Commission. For 
14        the purposes of this paragraph (6), "delivery year" 
15        has the meaning given to that term in Section 1-10 of 
16        the Illinois Power Agency Act, and "Agency" means the 
17        Illinois Power Agency.
18            (ii) The energy storage system resources 
19        procurement planning process shall be conducted as 
20        follows:
21                (A) The Agency shall publish for comment the 
22            initial energy storage system resources 
23            procurement plan no later than June 1, 2027 and 
24            may revise the plan at least every 2 years 
25            thereafter. To the extent practicable, the Agency 
26            shall review and propose any revisions to the 
 
 
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1            energy storage system resources procurement plan 
2            in conjunction with the Agency's long-term 
3            renewable resources procurement plan. The initial 
4            energy storage system resources plan shall:
5                    (aa) include a schedule for procurements 
6                for energy storage system resources consistent 
7                with subsection (d-20) of Section 1-75 of the 
8                Illinois Power Agency Act; and
9                    (bb) identify the process whereby the 
10                Agency will submit to the Commission for 
11                review and approval the proposed contracts to 
12                implement the programs required by the plan.
13                Copies of the initial energy storage system 
14            resources procurement plan and all subsequent 
15            revisions shall be posted and made publicly 
16            available on the Agency's and Commission's 
17            websites, and copies shall also be provided to 
18            each affected electric utility. An affected 
19            utility and other interested parties shall have 45 
20            days after the date of posting to provide comment 
21            to the Agency on the initial storage system 
22            resources procurement plan and all subsequent 
23            revisions. All comments shall be posted on the 
24            Agency's and the Commission's websites.
25                (B) The Commission shall approve the initial 
26            energy storage system resources procurement plan 
 
 
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1            and any subsequent revisions if the Commission 
2            determines that the plan will reasonably and 
3            prudently accomplish the requirements of 
4            subsection (d-20) of Section 1-75 of the Illinois 
5            Power Agency Act. The Commission shall also 
6            approve the process for the submission, review, 
7            and approval of the proposed contracts to procure 
8            energy storage system resources or implement the 
9            programs authorized by the Commission pursuant to 
10            an energy storage system resources procurement 
11            plan approved under this Section.
12            (iii) The Agency or third parties contracted by 
13        the Agency shall implement all programs authorized by 
14        the Commission in an approved energy storage system 
15        resources procurement plan without further review and 
16        approval by the Commission. Third parties shall not 
17        begin implementing any programs or receive any payment 
18        under this Section until the Commission has approved a 
19        contract under the energy storage system resources 
20        procurement process under this Section.
21            (iv) An electric utility shall recover its prudent 
22        and reasonable costs associated with the procurement 
23        of energy storage system resources procurements under 
24        this Section and under subsection (d-20) of Section 
25        1-75 of the Illinois Power Agency Act through an 
26        automatic adjustment clause tariff under subsection 
 
 
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1        (k) of Section 16-108.    
2    (b-5) An electric utility that as of January 1, 2019 
3served more than 300,000 retail customers in this State shall 
4purchase renewable energy credits from new renewable energy 
5facilities constructed at or adjacent to the sites of 
6coal-fueled electric generating facilities in this State in 
7accordance with subsection (c-5) of Section 1-75 of the 
8Illinois Power Agency Act and shall purchase energy storage 
9credits, or other services as applicable, for energy storage 
10system resources in accordance with subsection (d-20) of 
11Section 1-75 of the Illinois Power Agency Act. Except as 
12expressly provided in this Section, the plans and procedures 
13for such procurements shall not be included in the procurement 
14plans provided for in this Section, but rather shall be 
15conducted and implemented solely in accordance with subsection 
16(c-5) of Section 1-75 of the Illinois Power Agency Act.
17    (b-10) In recognition of the potential need to facilitate 
18additional supply to address any resource adequacy challenges 
19through a stable and competitively neutral cost allocation 
20mechanism, upon an identification of need by the Commission 
21pursuant to the integrated resource planning process outlined 
22in Section 16-201, the procurement plan described in 
23subsection (b) may also include the procurement of energy, 
24capacity, environmental attributes, resource adequacy 
25attributes, or some combination thereof intended to serve all 
26retail customers. Any procurements proposed under this 
 
 
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1subsection (b-10) shall feature long-term contracts, shall be 
2structured to facilitate new and additive supply resources, 
3and shall be sized to ensure that the substantial majority of 
4any load-serving entity's supply portfolio is not composed of 
5contracts awarded under this subsection (b-10).
6        (1) Facilities eligible for long-term contracts under 
7    this subsection (b-10) must be new clean energy resources, 
8    as defined in Section 1-10 of the Illinois Power Agency 
9    Act, including clean generation associated high voltage 
10    direct current transmission facilities, and must qualify 
11    as an accredited capacity resource within the service 
12    areas of PJM Interconnection, LLC, or Midcontinent 
13    Independent System Operator, Inc. For purposes of this 
14    subsection (b-10), "new" means energized on or after the 
15    effective date of this amendatory Act of the 104th General 
16    Assembly.
17        (2) Contracts may take the form of a sourcing 
18    agreement, power purchase agreement, or other instrument 
19    as determined by the Commission in approving the plan, and 
20    may feature fixed or variable pricing structures, 
21    including utilization of a contract for differences in 
22    pricing structure. Contracts may feature both electric 
23    utilities and alternative retail electric suppliers as 
24    counterparties. In approving the contract structure 
25    utilized for any contract awards made pursuant to this 
26    subsection (b-10), the Commission shall prioritize 
 
 
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1    structures that ensure stable, reliable, and competitively 
2    neutral allocations of costs and responsibilities.
3        (3) Purchases made under contracts awarded through 
4    this subsection (b-10) shall be funded in a competitively 
5    neutral manner as determined by the Commission in 
6    approving the plan. To meet contract obligations, the 
7    Commission may order collections from all retail customers 
8    or from all load-serving entities, including alternative 
9    retail electric suppliers as defined in Section 16-102 of 
10    this Act, as a means of ensuring a fair and competitively 
11    neutral allocation of contract costs. In establishing 
12    collections, the Agency may propose and the Commission may 
13    approve adjustments for load-serving entities that have 
14    contracts entered into before the effective date of this 
15    amendatory Act of the 104th General Assembly for energy, 
16    capacity, or environmental attributes.
17        (4) The Agency may propose and the Commission may 
18    approve additional terms, conditions, and requirements 
19    applicable to this procurement process through development 
20    and approval of the Agency's annual electricity 
21    procurement plan.
22        (5) The manner and form for developing contracts, 
23    qualifying potential counterparties, and awarding 
24    contracts shall be proposed as part of the annual 
25    electricity procurement plan described in this subsection 
26    (b-10). However, to the extent practicable, the proposed 
 
 
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1    approach for contract development and award should 
2    endeavor to follow the provisions of subsections (c) and 
3    (e) through (i) of this Section.
4        (6) As further outlined in Section 16-115A, compliance 
5    with any procurement process proposed under this 
6    subsection (b-10) shall be considered a condition of 
7    service for alternative retail electric suppliers.    
8    (c) The provisions of this subsection (c) shall not apply 
9to procurements conducted pursuant to subsection (c-5) of 
10Section 1-75 of the Illinois Power Agency Act. However, the 
11Agency may retain a procurement administrator to assist the 
12Agency in planning and carrying out the procurement events and 
13implementing the other requirements specified in such 
14subsection (c-5) of Section 1-75 of the Illinois Power Agency 
15Act, with the costs incurred by the Agency for the procurement 
16administrator to be recovered through fees charged to 
17applicants for selection to sell and deliver renewable energy 
18credits to electric utilities pursuant to subsection (c-5) of 
19Section 1-75 of the Illinois Power Agency Act. The procurement 
20process set forth in Section 1-75 of the Illinois Power Agency 
21Act and subsection (e) of this Section shall be administered 
22by a procurement administrator and monitored by a procurement 
23monitor.
24        (1) The procurement administrator shall:
25            (i) design the final procurement process in 
26        accordance with Section 1-75 of the Illinois Power 
 
 
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1        Agency Act and subsection (e) of this Section 
2        following Commission approval of the procurement plan;
3            (ii) develop benchmarks in accordance with 
4        subsection (e)(3) to be used to evaluate bids; these 
5        benchmarks shall be submitted to the Commission for 
6        review and approval on a confidential basis prior to 
7        the procurement event;
8            (iii) serve as the interface between the electric 
9        utility and suppliers;
10            (iv) manage the bidder pre-qualification and 
11        registration process;
12            (v) obtain the electric utilities' agreement to 
13        the final form of all supply contracts and credit 
14        collateral agreements;
15            (vi) administer the request for proposals process;
16            (vii) have the discretion to negotiate to 
17        determine whether bidders are willing to lower the 
18        price of bids that meet the benchmarks approved by the 
19        Commission; any post-bid negotiations with bidders 
20        shall be limited to price only and shall be completed 
21        within 24 hours after opening the sealed bids and 
22        shall be conducted in a fair and unbiased manner; in 
23        conducting the negotiations, there shall be no 
24        disclosure of any information derived from proposals 
25        submitted by competing bidders; if information is 
26        disclosed to any bidder, it shall be provided to all 
 
 
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1        competing bidders;
2            (viii) maintain confidentiality of supplier and 
3        bidding information in a manner consistent with all 
4        applicable laws, rules, regulations, and tariffs;
5            (ix) submit a confidential report to the 
6        Commission recommending acceptance or rejection of 
7        bids;
8            (x) notify the utility of contract counterparties 
9        and contract specifics; and
10            (xi) administer related contingency procurement 
11        events.
12        (2) The procurement monitor, who shall be retained by 
13    the Commission, shall:
14            (i) monitor interactions among the procurement 
15        administrator, suppliers, and utility;
16            (ii) monitor and report to the Commission on the 
17        progress of the procurement process;
18            (iii) provide an independent confidential report 
19        to the Commission regarding the results of the 
20        procurement event;
21            (iv) assess compliance with the procurement plans 
22        approved by the Commission for each utility that on 
23        December 31, 2005 provided electric service to at 
24        least 100,000 customers in Illinois and for each small 
25        multi-jurisdictional utility that on December 31, 2005 
26        served less than 100,000 customers in Illinois;
 
 
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1            (v) preserve the confidentiality of supplier and 
2        bidding information in a manner consistent with all 
3        applicable laws, rules, regulations, and tariffs;
4            (vi) provide expert advice to the Commission and 
5        consult with the procurement administrator regarding 
6        issues related to procurement process design, rules, 
7        protocols, and policy-related matters; and
8            (vii) consult with the procurement administrator 
9        regarding the development and use of benchmark 
10        criteria, standard form contracts, credit policies, 
11        and bid documents.
12    (d) Except as provided in subsection (j), the planning 
13process shall be conducted as follows:
14        (1) Beginning in 2008, each Illinois utility procuring 
15    power pursuant to this Section shall annually provide a 
16    range of load forecasts to the Illinois Power Agency by 
17    July 15 of each year, or such other date as may be required 
18    by the Commission or Agency. The load forecasts shall 
19    cover the 5-year procurement planning period for the next 
20    procurement plan and shall include hourly data 
21    representing a high-load, low-load, and expected-load 
22    scenario for the load of those retail customers included 
23    in the plan's electric supply service requirements. The 
24    utility shall provide supporting data and assumptions for 
25    each of the scenarios. 
26        (2) Beginning in 2008, the Illinois Power Agency shall 
 
 
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1    prepare a procurement plan by August 15th of each year, or 
2    such other date as may be required by the Commission. The 
3    procurement plan shall identify the portfolio of 
4    demand-response and power and energy products to be 
5    procured. Cost-effective demand-response measures shall be 
6    procured as set forth in item (iii) of subsection (b) of 
7    this Section. Copies of the procurement plan shall be 
8    posted and made publicly available on the Agency's and 
9    Commission's websites, and copies shall also be provided 
10    to each affected electric utility. An affected utility 
11    shall have 30 days following the date of posting to 
12    provide comment to the Agency on the procurement plan. 
13    Other interested entities also may comment on the 
14    procurement plan. All comments submitted to the Agency 
15    shall be specific, supported by data or other detailed 
16    analyses, and, if objecting to all or a portion of the 
17    procurement plan, accompanied by specific alternative 
18    wording or proposals. All comments shall be posted on the 
19    Agency's and Commission's websites. During this 30-day 
20    comment period, the Agency shall hold at least one virtual 
21    or in-person public hearing for within each utility's 
22    service area for the purpose of receiving public comment 
23    on the procurement plan. Within 14 days following the end 
24    of the 30-day review period, the Agency shall revise the 
25    procurement plan as necessary based on the comments 
26    received and file the procurement plan with the Commission 
 
 
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1    and post the procurement plan on the websites.
2        (3) Within 5 days after the filing of the procurement 
3    plan, any person objecting to the procurement plan shall 
4    file an objection with the Commission. Within 10 days 
5    after the filing, the Commission shall determine whether a 
6    hearing is necessary. The Commission shall enter its order 
7    confirming or modifying the procurement plan within 90 
8    days after the filing of the procurement plan by the 
9    Illinois Power Agency.
10        (4) The Commission shall approve the procurement plan, 
11    including expressly the forecast used in the procurement 
12    plan, if the Commission determines that it will ensure 
13    adequate, reliable, affordable, efficient, and 
14    environmentally sustainable electric service at the lowest 
15    total cost over time, taking into account any benefits of 
16    price stability.
17        (4.5) The Commission shall review the Agency's 
18    recommendations for the selection of applicants to enter 
19    into long-term contracts for the sale and delivery of 
20    renewable energy credits from new renewable energy 
21    facilities to be constructed at or adjacent to the sites 
22    of coal-fueled electric generating facilities in this 
23    State in accordance with the provisions of subsection 
24    (c-5) of Section 1-75 of the Illinois Power Agency Act, 
25    and shall approve the Agency's recommendations if the 
26    Commission determines that the applicants recommended by 
 
 
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1    the Agency for selection, the proposed new renewable 
2    energy facilities to be constructed, the amounts of 
3    renewable energy credits to be delivered pursuant to the 
4    contracts, and the other terms of the contracts, are 
5    consistent with the requirements of subsection (c-5) of 
6    Section 1-75 of the Illinois Power Agency Act. 
7    (e) The procurement process shall include each of the 
8following components:
9        (1) Solicitation, pre-qualification, and registration 
10    of bidders. The procurement administrator shall 
11    disseminate information to potential bidders to promote a 
12    procurement event, notify potential bidders that the 
13    procurement administrator may enter into a post-bid price 
14    negotiation with bidders that meet the applicable 
15    benchmarks, provide supply requirements, and otherwise 
16    explain the competitive procurement process. In addition 
17    to such other publication as the procurement administrator 
18    determines is appropriate, this information shall be 
19    posted on the Illinois Power Agency's and the Commission's 
20    websites. The procurement administrator shall also 
21    administer the prequalification process, including 
22    evaluation of credit worthiness, compliance with 
23    procurement rules, and agreement to the standard form 
24    contract developed pursuant to paragraph (2) of this 
25    subsection (e). The procurement administrator shall then 
26    identify and register bidders to participate in the 
 
 
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1    procurement event.
2        (2) Standard contract forms and credit terms and 
3    instruments. The procurement administrator, in 
4    consultation with the utilities, the Commission, and other 
5    interested parties and subject to Commission oversight, 
6    shall develop and provide standard contract forms for the 
7    supplier contracts that meet generally accepted industry 
8    practices. Standard credit terms and instruments that meet 
9    generally accepted industry practices shall be similarly 
10    developed. The procurement administrator shall make 
11    available to the Commission all written comments it 
12    receives on the contract forms, credit terms, or 
13    instruments. If the procurement administrator cannot reach 
14    agreement with the applicable electric utility as to the 
15    contract terms and conditions, the procurement 
16    administrator must notify the Commission of any disputed 
17    terms and the Commission shall resolve the dispute. The 
18    terms of the contracts shall not be subject to negotiation 
19    by winning bidders, and the bidders must agree to the 
20    terms of the contract in advance so that winning bids are 
21    selected solely on the basis of price.
22        (3) Establishment of a market-based price benchmark. 
23    As part of the development of the procurement process, the 
24    procurement administrator, in consultation with the 
25    Commission staff, Agency staff, and the procurement 
26    monitor, shall establish benchmarks for evaluating the 
 
 
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1    final prices in the contracts for each of the products 
2    that will be procured through the procurement process. The 
3    benchmarks shall be based on price data for similar 
4    products for the same delivery period and same delivery 
5    hub, or other delivery hubs after adjusting for that 
6    difference. The price benchmarks may also be adjusted to 
7    take into account differences between the information 
8    reflected in the underlying data sources and the specific 
9    products and procurement process being used to procure 
10    power for the Illinois utilities. The benchmarks shall be 
11    confidential but shall be provided to, and will be subject 
12    to Commission review and approval, prior to a procurement 
13    event.
14        (4) Request for proposals competitive procurement 
15    process. The procurement administrator shall design and 
16    issue a request for proposals to supply electricity in 
17    accordance with each utility's procurement plan, as 
18    approved by the Commission. The request for proposals 
19    shall set forth a procedure for sealed, binding commitment 
20    bidding with pay-as-bid settlement, and provision for 
21    selection of bids on the basis of price.
22        (5) A plan for implementing contingencies in the event 
23    of supplier default or failure of the procurement process 
24    to fully meet the expected load requirement due to 
25    insufficient supplier participation, Commission rejection 
26    of results, or any other cause.
 
 
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1            (i) Event of supplier default: In the event of 
2        supplier default, the utility shall review the 
3        contract of the defaulting supplier to determine if 
4        the amount of supply is 200 megawatts or greater, and 
5        if there are more than 60 days remaining of the 
6        contract term. If both of these conditions are met, 
7        and the default results in termination of the 
8        contract, the utility shall immediately notify the 
9        Illinois Power Agency that a request for proposals 
10        must be issued to procure replacement power, and the 
11        procurement administrator shall run an additional 
12        procurement event. If the contracted supply of the 
13        defaulting supplier is less than 200 megawatts or 
14        there are less than 60 days remaining of the contract 
15        term, the utility shall procure power and energy from 
16        the applicable regional transmission organization 
17        market, including ancillary services, capacity, and 
18        day-ahead or real time energy, or both, for the 
19        duration of the contract term to replace the 
20        contracted supply; provided, however, that if a needed 
21        product is not available through the regional 
22        transmission organization market it shall be purchased 
23        from the wholesale market.
24            (ii) Failure of the procurement process to fully 
25        meet the expected load requirement: If the procurement 
26        process fails to fully meet the expected load 
 
 
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1        requirement due to insufficient supplier participation 
2        or due to a Commission rejection of the procurement 
3        results, the procurement administrator, the 
4        procurement monitor, and the Commission staff shall 
5        meet within 10 days to analyze potential causes of low 
6        supplier interest or causes for the Commission 
7        decision. If changes are identified that would likely 
8        result in increased supplier participation, or that 
9        would address concerns causing the Commission to 
10        reject the results of the prior procurement event, the 
11        procurement administrator may implement those changes 
12        and rerun the request for proposals process according 
13        to a schedule determined by those parties and 
14        consistent with Section 1-75 of the Illinois Power 
15        Agency Act and this subsection. In any event, a new 
16        request for proposals process shall be implemented by 
17        the procurement administrator within 90 days after the 
18        determination that the procurement process has failed 
19        to fully meet the expected load requirement.
20            (iii) In all cases where there is insufficient 
21        supply provided under contracts awarded through the 
22        procurement process to fully meet the electric 
23        utility's load requirement, the utility shall meet the 
24        load requirement by procuring power and energy from 
25        the applicable regional transmission organization 
26        market, including ancillary services, capacity, and 
 
 
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1        day-ahead or real time energy, or both; provided, 
2        however, that if a needed product is not available 
3        through the regional transmission organization market 
4        it shall be purchased from the wholesale market.
5        (6) The procurement processes described in this 
6    subsection and in subsection (c-5) of Section 1-75 of the 
7    Illinois Power Agency Act are exempt from the requirements 
8    of the Illinois Procurement Code, pursuant to Section 
9    20-10 of that Code.
10    (f) Within 2 business days after opening the sealed bids, 
11the procurement administrator shall submit a confidential 
12report to the Commission. The report shall contain the results 
13of the bidding for each of the products along with the 
14procurement administrator's recommendation for the acceptance 
15and rejection of bids based on the price benchmark criteria 
16and other factors observed in the process. The procurement 
17monitor also shall submit a confidential report to the 
18Commission within 2 business days after opening the sealed 
19bids. The report shall contain the procurement monitor's 
20assessment of bidder behavior in the process as well as an 
21assessment of the procurement administrator's compliance with 
22the procurement process and rules. The Commission shall review 
23the confidential reports submitted by the procurement 
24administrator and procurement monitor, and shall accept or 
25reject the recommendations of the procurement administrator 
26within 2 business days after receipt of the reports.
 
 
10400SB0025ham002- 701 -LRB104 07069 AAS 28576 a

1    (g) Within 3 business days after the Commission decision 
2approving the results of a procurement event, the utility 
3shall enter into binding contractual arrangements with the 
4winning suppliers using the standard form contracts; except 
5that the utility shall not be required either directly or 
6indirectly to execute the contracts if a tariff that is 
7consistent with subsection (l) of this Section has not been 
8approved and placed into effect for that utility.
9    (h) For the procurement of standard wholesale products, 
10the names of the successful bidders and the load weighted 
11average of the winning bid prices for each contract type and 
12for each contract term shall be made available to the public at 
13the time of Commission approval of a procurement event. For 
14procurements conducted to meet the requirements of subsection 
15(b) of Section 1-56 or subsection (c) of Section 1-75 of the 
16Illinois Power Agency Act governed by the provisions of this 
17Section, the address and nameplate capacity of the new 
18renewable energy generating facility proposed by a winning 
19bidder shall also be made available to the public at the time 
20of Commission approval of a procurement event, along with the 
21business address and contact information for any winning 
22bidder. An estimate or approximation of the nameplate capacity 
23of the new renewable energy generating facility may be 
24disclosed if necessary to protect the confidentiality of 
25individual bid prices.
26    The Commission, the procurement monitor, the procurement 
 
 
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1administrator, the Illinois Power Agency, and all participants 
2in the procurement process shall maintain the confidentiality 
3of all other supplier and bidding information in a manner 
4consistent with all applicable laws, rules, regulations, and 
5tariffs. Confidential information, including the confidential 
6reports submitted by the procurement administrator and 
7procurement monitor pursuant to subsection (f) of this 
8Section, shall not be made publicly available and shall not be 
9discoverable by any party in any proceeding, absent a 
10compelling demonstration of need, nor shall those reports be 
11admissible in any proceeding other than one for law 
12enforcement purposes.
13    For procurements conducted to meet the requirements of 
14subsection (b) of Section 1-56 or subsection (c) of Section 
151-75 of the Illinois Power Agency Act, the Illinois Power 
16Agency may release aggregated information related to 
17participation levels across product types and the basis of 
18rejection for non-accepted bids if the Commission, the 
19procurement monitor, the procurement administrator, and the 
20Illinois Power Agency determine that the release of this 
21information would not result in the disclosure of confidential 
22bid information or negatively impact the competitiveness of 
23future renewable energy credit procurements. The Agency may 
24also release information about the development status of new 
25renewable energy projects under contract and project-specific 
26information about renewable energy credit delivery quantities 
 
 
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1for projects under contract if the Commission, the procurement 
2monitor, the procurement administrator, and the Illinois Power 
3Agency determine that the release of this information would 
4not result in the disclosure of confidential bid information 
5or negatively impact the competitiveness of future renewable 
6energy credit procurements.    
7    (i) Within 2 business days after a Commission decision 
8approving the results of a procurement event or such other 
9date as may be required by the Commission from time to time, 
10the utility shall file for informational purposes with the 
11Commission its actual or estimated retail supply charges, as 
12applicable, by customer supply group reflecting the costs 
13associated with the procurement and computed in accordance 
14with the tariffs filed pursuant to subsection (l) of this 
15Section and approved by the Commission.
16    (j) Within 60 days following August 28, 2007 (the 
17effective date of Public Act 95-481), each electric utility 
18that on December 31, 2005 provided electric service to at 
19least 100,000 customers in Illinois shall prepare and file 
20with the Commission an initial procurement plan, which shall 
21conform in all material respects to the requirements of the 
22procurement plan set forth in subsection (b); provided, 
23however, that the Illinois Power Agency Act shall not apply to 
24the initial procurement plan prepared pursuant to this 
25subsection. The initial procurement plan shall identify the 
26portfolio of power and energy products to be procured and 
 
 
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1delivered for the period June 2008 through May 2009, and shall 
2identify the proposed procurement administrator, who shall 
3have the same experience and expertise as is required of a 
4procurement administrator hired pursuant to Section 1-75 of 
5the Illinois Power Agency Act. Copies of the procurement plan 
6shall be posted and made publicly available on the 
7Commission's website. The initial procurement plan may include 
8contracts for renewable resources that extend beyond May 2009.
9        (i) Within 14 days following filing of the initial 
10    procurement plan, any person may file a detailed objection 
11    with the Commission contesting the procurement plan 
12    submitted by the electric utility. All objections to the 
13    electric utility's plan shall be specific, supported by 
14    data or other detailed analyses. The electric utility may 
15    file a response to any objections to its procurement plan 
16    within 7 days after the date objections are due to be 
17    filed. Within 7 days after the date the utility's response 
18    is due, the Commission shall determine whether a hearing 
19    is necessary. If it determines that a hearing is 
20    necessary, it shall require the hearing to be completed 
21    and issue an order on the procurement plan within 60 days 
22    after the filing of the procurement plan by the electric 
23    utility.
24        (ii) The order shall approve or modify the procurement 
25    plan, approve an independent procurement administrator, 
26    and approve or modify the electric utility's tariffs that 
 
 
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1    are proposed with the initial procurement plan. The 
2    Commission shall approve the procurement plan if the 
3    Commission determines that it will ensure adequate, 
4    reliable, affordable, efficient, and environmentally 
5    sustainable electric service at the lowest total cost over 
6    time, taking into account any benefits of price stability.
7    (k) (Blank).
8    (k-5) (Blank).
9    (l) An electric utility shall recover its costs incurred 
10under this Section and subsection (c-5) of Section 1-75 of the 
11Illinois Power Agency Act, including, but not limited to, the 
12costs of procuring power and energy demand-response resources 
13under this Section and its costs for purchasing renewable 
14energy credits pursuant to subsection (c-5) of Section 1-75 of 
15the Illinois Power Agency Act. The utility shall file with the 
16initial procurement plan its proposed tariffs through which 
17its costs of procuring power that are incurred pursuant to a 
18Commission-approved procurement plan and those other costs 
19identified in this subsection (l), will be recovered. The 
20tariffs shall include a formula rate or charge designed to 
21pass through both the costs incurred by the utility in 
22procuring a supply of electric power and energy for the 
23applicable customer classes with no mark-up or return on the 
24price paid by the utility for that supply, plus any just and 
25reasonable costs that the utility incurs in arranging and 
26providing for the supply of electric power and energy. The 
 
 
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1formula rate or charge shall also contain provisions that 
2ensure that its application does not result in over or under 
3recovery due to changes in customer usage and demand patterns, 
4and that provide for the correction, on at least an annual 
5basis, of any accounting errors that may occur. A utility 
6shall recover through the tariff all reasonable costs incurred 
7to implement or comply with any procurement plan that is 
8developed and put into effect pursuant to Section 1-75 of the 
9Illinois Power Agency Act and this Section, and for the 
10procurement of renewable energy credits pursuant to subsection 
11(c-5) of Section 1-75 of the Illinois Power Agency Act, 
12including any fees assessed by the Illinois Power Agency, 
13costs associated with load balancing, and contingency plan 
14costs. The electric utility shall also recover its full costs 
15of procuring electric supply for which it contracted before 
16the effective date of this Section in conjunction with the 
17provision of full requirements service under fixed-price 
18bundled service tariffs subsequent to December 31, 2006. All 
19such costs shall be deemed to have been prudently incurred. 
20The pass-through tariffs that are filed and approved pursuant 
21to this Section shall not be subject to review under, or in any 
22way limited by, Section 16-111(i) of this Act. All of the costs 
23incurred by the electric utility associated with the purchase 
24of zero emission credits in accordance with subsection (d-5) 
25of Section 1-75 of the Illinois Power Agency Act, all costs 
26incurred by the electric utility associated with the purchase 
 
 
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1of carbon mitigation credits in accordance with subsection 
2(d-10) of Section 1-75 of the Illinois Power Agency Act, and, 
3beginning June 1, 2017, all of the costs incurred by the 
4electric utility associated with the purchase of renewable 
5energy resources in accordance with Sections 1-56 and 1-75 of 
6the Illinois Power Agency Act, and all of the costs incurred by 
7the electric utility in purchasing renewable energy credits in 
8accordance with subsection (c-5) of Section 1-75 of the 
9Illinois Power Agency Act, shall be recovered through the 
10electric utility's tariffed charges applicable to all of its 
11retail customers, as specified in subsection (k) or subsection 
12(i-5), as applicable, of Section 16-108 of this Act, and shall 
13not be recovered through the electric utility's tariffed 
14charges for electric power and energy supply to its eligible 
15retail customers.
16    (m) The Commission has the authority to adopt rules to 
17carry out the provisions of this Section. For the public 
18interest, safety, and welfare, the Commission also has 
19authority to adopt rules to carry out the provisions of this 
20Section on an emergency basis immediately following August 28, 
212007 (the effective date of Public Act 95-481).
22    (n) Notwithstanding any other provision of this Act, any 
23affiliated electric utilities that submit a single procurement 
24plan covering their combined needs may procure for those 
25combined needs in conjunction with that plan, and may enter 
26jointly into power supply contracts, purchases, and other 
 
 
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1procurement arrangements, and allocate capacity and energy and 
2cost responsibility therefor among themselves in proportion to 
3their requirements.
4    (o) On or before June 1 of each year, the Commission shall 
5hold an informal hearing for the purpose of receiving comments 
6on the prior year's procurement process and any 
7recommendations for change. 
8    (p) An electric utility subject to this Section may 
9propose to invest, lease, own, or operate an electric 
10generation facility as part of its procurement plan, provided 
11the utility demonstrates that such facility is the least-cost 
12option to provide electric service to those retail customers 
13included in the plan's electric supply service requirements. 
14If the facility is shown to be the least-cost option and is 
15included in a procurement plan prepared in accordance with 
16Section 1-75 of the Illinois Power Agency Act and this 
17Section, then the electric utility shall make a filing 
18pursuant to Section 8-406 of this Act, and may request of the 
19Commission any statutory relief required thereunder. If the 
20Commission grants all of the necessary approvals for the 
21proposed facility, such supply shall thereafter be considered 
22as a pre-existing contract under subsection (b) of this 
23Section. The Commission shall in any order approving a 
24proposal under this subsection specify how the utility will 
25recover the prudently incurred costs of investing in, leasing, 
26owning, or operating such generation facility through just and 
 
 
10400SB0025ham002- 709 -LRB104 07069 AAS 28576 a

1reasonable rates charged to those retail customers included in 
2the plan's electric supply service requirements. Cost recovery 
3for facilities included in the utility's procurement plan 
4pursuant to this subsection shall not be subject to review 
5under or in any way limited by the provisions of Section 
616-111(i) of this Act. Nothing in this Section is intended to 
7prohibit a utility from filing for a fuel adjustment clause as 
8is otherwise permitted under Section 9-220 of this Act. 
9    (q) If the Illinois Power Agency filed with the 
10Commission, under Section 16-111.5 of this Act, its proposed 
11procurement plan for the period commencing June 1, 2017, and 
12the Commission has not yet entered its final order approving 
13the plan on or before the effective date of this amendatory Act 
14of the 99th General Assembly, then the Illinois Power Agency 
15shall file a notice of withdrawal with the Commission, after 
16the effective date of this amendatory Act of the 99th General 
17Assembly, to withdraw the proposed procurement of renewable 
18energy resources to be approved under the plan, other than the 
19procurement of renewable energy credits from distributed 
20renewable energy generation devices using funds previously 
21collected from electric utilities' retail customers that take 
22service pursuant to electric utilities' hourly pricing tariff 
23or tariffs and, for an electric utility that serves less than 
24100,000 retail customers in the State, other than the 
25procurement of renewable energy credits from distributed 
26renewable energy generation devices. Upon receipt of the 
 
 
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1notice, the Commission shall enter an order that approves the 
2withdrawal of the proposed procurement of renewable energy 
3resources from the plan. The initially proposed procurement of 
4renewable energy resources shall not be approved or be the 
5subject of any further hearing, investigation, proceeding, or 
6order of any kind.
7    This amendatory Act of the 99th General Assembly preempts 
8and supersedes any order entered by the Commission that 
9approved the Illinois Power Agency's procurement plan for the 
10period commencing June 1, 2017, to the extent it is 
11inconsistent with the provisions of this amendatory Act of the 
1299th General Assembly. To the extent any previously entered 
13order approved the procurement of renewable energy resources, 
14the portion of that order approving the procurement shall be 
15void, other than the procurement of renewable energy credits 
16from distributed renewable energy generation devices using 
17funds previously collected from electric utilities' retail 
18customers that take service under electric utilities' hourly 
19pricing tariff or tariffs and, for an electric utility that 
20serves less than 100,000 retail customers in the State, other 
21than the procurement of renewable energy credits for 
22distributed renewable energy generation devices. 
23(Source: P.A. 102-662, eff. 9-15-21.)
 
24    (220 ILCS 5/16-111.7)
25    Sec. 16-111.7. On-bill financing program; electric 
 
 
10400SB0025ham002- 711 -LRB104 07069 AAS 28576 a

1utilities.
2    (a) The Illinois General Assembly finds that Illinois 
3homes and businesses have the potential to save energy through 
4conservation and cost-effective energy efficiency measures. 
5Programs created pursuant to this Section will allow utility 
6customers to purchase cost-effective energy efficiency 
7measures, including measures set forth in a 
8Commission-approved energy efficiency and demand-response plan 
9under Section 8-103 or 8-103B of this Act, with no required 
10initial upfront payment, and to pay the cost of those products 
11and services over time on their utility bill.
12    (b) Notwithstanding any other provision of this Act, an 
13electric utility serving more than 100,000 customers on 
14January 1, 2009 shall offer a Commission-approved on-bill 
15financing program ("program") that allows its eligible retail 
16customers, as that term is defined in Section 16-111.5 of this 
17Act, who own a residential single family home, duplex, or 
18other residential building with 4 or less units, or 
19condominium at which the electric service is being provided 
20(i) to borrow funds from a third party lender in order to 
21purchase electric energy efficiency measures approved under 
22the program for installation in such home or condominium 
23without any required upfront payment and (ii) to pay back such 
24funds over time through the electric utility's bill. Based 
25upon the process described in subsection (b-5) of this 
26Section, small commercial customers who own the premises at 
 
 
10400SB0025ham002- 712 -LRB104 07069 AAS 28576 a

1which electric service is being provided may be included in 
2such program. After receiving a request from an electric 
3utility for approval of a proposed program and tariffs 
4pursuant to this Section, the Commission shall render its 
5decision within 120 days. If no decision is rendered within 
6120 days, then the request shall be deemed to be approved.
7    Beginning no later than December 31, 2013, an electric 
8utility subject to this subsection (b) shall also offer its 
9program to eligible retail customers that own multifamily 
10residential or mixed-use buildings with no more than 50 
11residential units, provided, however, that such customers must 
12either be a residential customer or small commercial customer 
13and may not use the program in such a way that repayment of the 
14cost of energy efficiency measures is made through tenants' 
15utility bills. An electric utility may impose a per site loan 
16limit not to exceed $150,000. The program, and loans issued 
17thereunder, shall only be offered to customers of the utility 
18that meet the requirements of this Section and that also have 
19an electric service account at the premises where the energy 
20efficiency measures being financed shall be installed. 
21Beginning no later than 2 years after the effective date of 
22this amendatory Act of the 99th General Assembly, the 50 
23residential unit limitation described in this paragraph shall 
24no longer apply, and the utility shall replace the per site 
25loan limit of $150,000 with a loan limit that correlates to a 
26maximum monthly payment that does not exceed 50% of the 
 
 
10400SB0025ham002- 713 -LRB104 07069 AAS 28576 a

1customer's average utility bill over the prior 12-month 
2period.
3    Beginning no later than 2 years after the effective date 
4of this amendatory Act of the 99th General Assembly, an 
5electric utility subject to this subsection (b) shall also 
6offer its program to eligible retail customers that are Unit 
7Owners' Associations, as defined in subsection (o) of Section 
82 of the Condominium Property Act, or Master Associations, as 
9defined in subsection (u) of the Condominium Property Act. 
10However, such customers must either be residential customers 
11or small commercial customers and may not use the program in 
12such a way that repayment of the cost of energy efficiency 
13measures is made through unit owners' utility bills. The 
14program and loans issued under the program shall only be 
15offered to customers of the utility that meet the requirements 
16of this Section and that also have an electric service account 
17at the premises where the energy efficiency measures being 
18financed shall be installed. 
19    For purposes of this Section, "small commercial customer" 
20means, for an electric utility serving more than 3,000,000 
21retail customers, those customers having peak demand of less 
22than 100 kilowatts, and, for an electric utility serving less 
23than 3,000,000 retail customers, those customers having peak 
24demand of less than 150 kilowatts; provided, however, that in 
25the event the Commission, after the effective date of this 
26amendatory Act of the 98th General Assembly, approves changes 
 
 
10400SB0025ham002- 714 -LRB104 07069 AAS 28576 a

1to a utility's tariffs that reflects new or revised demand 
2criteria for the utility's customer rate classifications, then 
3the utility may file a petition with the Commission to revise 
4the applicable definition of a small commercial customer to 
5reflect the new or revised demand criteria for the purposes of 
6this Section. After notice and hearing, the Commission shall 
7enter an order approving, or approving with modification, the 
8revised definition within 60 days after the utility files the 
9petition. 
10    (b-5) Within 30 days after the effective date of this 
11amendatory Act of the 96th General Assembly, the Commission 
12shall convene a workshop process during which interested 
13participants may discuss issues related to the program, 
14including program design, eligible electric energy efficiency 
15measures, vendor qualifications, and a methodology for 
16ensuring ongoing compliance with such qualifications, 
17financing, sample documents such as request for proposals, 
18contracts and agreements, dispute resolution, pre-installment 
19and post-installment verification, and evaluation. The 
20workshop process shall be completed within 150 days after the 
21effective date of this amendatory Act of the 96th General 
22Assembly.
23    (c) Not later than 60 days following completion of the 
24workshop process described in subsection (b-5) of this 
25Section, each electric utility subject to subsection (b) of 
26this Section shall submit a proposed program to the Commission 
 
 
10400SB0025ham002- 715 -LRB104 07069 AAS 28576 a

1that contains the following components:
2        (1) A list of recommended electric energy efficiency 
3    measures that will be eligible for on-bill financing. An 
4    eligible electric energy efficiency measure ("measure") 
5    shall be a product or service for which one or more of the 
6    following is true:
7            (A) (blank); 
8            (B) the projected electricity savings (determined 
9        by rates in effect at the time of purchase) are 
10        sufficient to cover the costs of implementing the 
11        measures, including finance charges and any program 
12        fees not recovered pursuant to subsection (f) of this 
13        Section; or
14            (C) the product or service is included in a 
15        Commission-approved energy efficiency and 
16        demand-response plan under Section 8-103 or 8-103B of 
17        this Act. 
18        (1.5) Beginning no later than 2 years after the 
19    effective date of this amendatory Act of the 99th General 
20    Assembly, an eligible electric energy efficiency measure 
21    (measure) shall be a product or service that qualifies 
22    under subparagraph (B) or (C) of paragraph (1) of this 
23    subsection (c) or for which one or more of the following is 
24    true:
25            (A) a building energy assessment, performed by an 
26        energy auditor who is certified by the Building 
 
 
10400SB0025ham002- 716 -LRB104 07069 AAS 28576 a

1        Performance Institute or who holds a similar 
2        certification, has recommended the product or service 
3        as likely to be cost effective over the course of its 
4        installed life for the building in which the measure 
5        is to be installed; or
6            (B) the product or service is necessary to safely 
7        or correctly install to code or industry standard an 
8        efficiency measure, including, but not limited to, 
9        installation work; changes needed to plumbing or 
10        electrical connections; upgrades to wiring or 
11        fixtures; removal of hazardous materials; correction 
12        of leaks; changes to thermostats, controls, or similar 
13        devices; and changes to venting or exhaust 
14        necessitated by the measure. However, the costs of the 
15        product or service described in this subparagraph (B) 
16        shall not exceed 25% of the total cost of installing 
17        the measure. 
18        (2) The electric utility shall issue a request for 
19    proposals ("RFP") to lenders for purposes of providing 
20    financing to participants to pay for approved measures. 
21    The RFP criteria shall include, but not be limited to, the 
22    interest rate, origination fees, and credit terms. The 
23    utility shall select the winning bidders based on its 
24    evaluation of these criteria, with a preference for those 
25    bids containing the rates, fees, and terms most favorable 
26    to participants;
 
 
10400SB0025ham002- 717 -LRB104 07069 AAS 28576 a

1        (3) The utility shall work with the lenders selected 
2    pursuant to the RFP process, and with vendors, to 
3    establish the terms and processes pursuant to which a 
4    participant can purchase eligible electric energy 
5    efficiency measures using the financing obtained from the 
6    lender. The vendor shall explain and offer the approved 
7    financing packaging to those customers identified in 
8    subsection (b) of this Section and shall assist customers 
9    in applying for financing. As part of the process, vendors 
10    shall also provide to participants information about any 
11    other incentives that may be available for the measures.
12        (4) The lender shall conduct credit checks or 
13    undertake other appropriate measures to limit credit risk, 
14    and shall review and approve or deny financing 
15    applications submitted by customers identified in 
16    subsection (b) of this Section. Following the lender's 
17    approval of financing and the participant's purchase of 
18    the measure or measures, the lender shall forward payment 
19    information to the electric utility, and the utility shall 
20    add as a separate line item on the participant's utility 
21    bill a charge showing the amount due under the program 
22    each month.
23        (5) A loan issued to a participant pursuant to the 
24    program shall be the sole responsibility of the 
25    participant, and any dispute that may arise concerning the 
26    loan's terms, conditions, or charges shall be resolved 
 
 
10400SB0025ham002- 718 -LRB104 07069 AAS 28576 a

1    between the participant and lender. Upon transfer of the 
2    property title for the premises at which the participant 
3    receives electric service from the utility or the 
4    participant's request to terminate service at such 
5    premises, the participant shall pay in full its electric 
6    utility bill, including all amounts due under the program, 
7    provided that this obligation may be modified as provided 
8    in subsection (g) of this Section. Amounts due under the 
9    program shall be deemed amounts owed for residential and, 
10    as appropriate, small commercial electric service.
11        (6) The electric utility shall remit payment in full 
12    to the lender each month on behalf of the participant. In 
13    the event a participant defaults on payment of its 
14    electric utility bill, the electric utility shall continue 
15    to remit all payments due under the program to the lender, 
16    and the utility shall be entitled to recover all costs 
17    related to a participant's nonpayment through the 
18    automatic adjustment clause tariff established pursuant to 
19    Section 16-111.8 of this Act. In addition, the electric 
20    utility shall retain a security interest in the measure or 
21    measures purchased under the program, and the utility 
22    retains its right to disconnect a participant that 
23    defaults on the payment of its utility bill.
24        (7) The total outstanding amount financed under the 
25    program in this subsection and subsection (c-5) of this 
26    Section shall not exceed $2.5 million for an electric 
 
 
10400SB0025ham002- 719 -LRB104 07069 AAS 28576 a

1    utility or electric utilities under a single holding 
2    company, provided that the electric utility or electric 
3    utilities may petition the Commission for an increase in 
4    such amount. Beginning after the effective date of this 
5    amendatory Act of the 99th General Assembly, the total 
6    maximum outstanding amount financed under the program in 
7    this subsection and subsections (c-5) and (c-10) of this 
8    Section shall increase by $5,000,000 per year until such 
9    time as the total maximum outstanding amount financed 
10    reaches $20,000,000. For purposes of this Section, 
11    "maximum outstanding amount financed" means the sum of all 
12    principal that has been loaned and not yet repaid. 
13    (c-5) Within 120 days after the effective date of this 
14amendatory Act of the 98th General Assembly, each electric 
15utility subject to the requirements of this Section shall 
16submit an informational filing to the Commission that 
17describes its plan for implementing the provisions of this 
18amendatory Act of the 98th General Assembly on or before 
19December 31, 2013. Such filing shall also describe how the 
20electric utility shall coordinate its program with any gas 
21utility or utilities that provide gas service to buildings 
22within the electric utility's service territory so that it is 
23practical and feasible for the owner of a multifamily building 
24to make a single application to access loans for both gas and 
25electric energy efficiency measures in any individual 
26building.
 
 
10400SB0025ham002- 720 -LRB104 07069 AAS 28576 a

1    (c-10) No later than 365 days after the effective date of 
2this amendatory Act of the 99th General Assembly, each 
3electric utility subject to the requirements of this Section 
4shall submit an informational filing to the Commission that 
5describes its plan for implementing the provisions of this 
6amendatory Act of the 99th General Assembly that were 
7incorporated into this Section. Such filing shall also include 
8the criteria to be used by the program for determining if 
9measures to be financed are eligible electric energy 
10efficiency measures, as defined by paragraph (1.5) of 
11subsection (c) of this Section. 
12    (d) A program approved by the Commission shall also 
13include the following criteria and guidelines for such 
14program:
15        (1) guidelines for financing of measures installed 
16    under a program, including, but not limited to, RFP 
17    criteria and limits on both individual loan amounts and 
18    the duration of the loans;
19        (2) criteria and standards for identifying and 
20    approving measures;
21        (3) qualifications of vendors that will market or 
22    install measures, as well as a methodology for ensuring 
23    ongoing compliance with such qualifications;
24        (4) sample contracts and agreements necessary to 
25    implement the measures and program; and
26        (5) the types of data and information that utilities 
 
 
10400SB0025ham002- 721 -LRB104 07069 AAS 28576 a

1    and vendors participating in the program shall collect for 
2    purposes of preparing the reports required under 
3    subsection (g) of this Section.
4    (e) The proposed program submitted by each electric 
5utility shall be consistent with the provisions of this 
6Section that define operational, financial and billing 
7arrangements between and among program participants, vendors, 
8lenders, and the electric utility.
9    (f) An electric utility shall recover all of the prudently 
10incurred costs of offering a program approved by the 
11Commission pursuant to this Section, including, but not 
12limited to, all start-up and administrative costs and the 
13costs for program evaluation. All prudently incurred costs 
14under this Section shall be recovered from the residential and 
15small commercial retail customer classes eligible to 
16participate in the program through the automatic adjustment 
17clause tariff established pursuant to Section 8-103 or 8-103B 
18of this Act.
19    (g) An independent evaluation of a program shall be 
20conducted after 3 years of the program's operation. The 
21electric utility shall retain an independent evaluator who 
22shall evaluate the effects of the measures installed under the 
23program and the overall operation of the program, including, 
24but not limited to, customer eligibility criteria and whether 
25the payment obligation for permanent electric energy 
26efficiency measures that will continue to provide benefits of 
 
 
10400SB0025ham002- 722 -LRB104 07069 AAS 28576 a

1energy savings should attach to the meter location. As part of 
2the evaluation process, the evaluator shall also solicit 
3feedback from participants and interested stakeholders. The 
4evaluator shall issue a report to the Commission on its 
5findings no later than 4 years after the date on which the 
6program commenced, and the Commission shall issue a report to 
7the Governor and General Assembly including a summary of the 
8information described in this Section as well as its 
9recommendations as to whether the program should be 
10discontinued, continued with modification or modifications or 
11continued without modification, provided that any recommended 
12modifications shall only apply prospectively and to measures 
13not yet installed or financed.
14    (h) An electric utility offering a Commission-approved 
15program pursuant to this Section shall not be required to 
16comply with any other statute, order, rule, or regulation of 
17this State that may relate to the offering of such program, 
18provided that nothing in this Section is intended to limit the 
19electric utility's obligation to comply with this Act and the 
20Commission's orders, rules, and regulations, including Part 
21280 of Title 83 of the Illinois Administrative Code.
22    (i) The source of a utility customer's electric supply 
23shall not disqualify a customer from participation in the 
24utility's on-bill financing program. Customers of alternative 
25retail electric suppliers may participate in the program under 
26the same terms and conditions applicable to the utility's 
 
 
10400SB0025ham002- 723 -LRB104 07069 AAS 28576 a

1supply customers.
2    (j) This Section is repealed on January 1, 2027.    
3(Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17.)
 
4    (220 ILCS 5/16-115A)
5    Sec. 16-115A. Obligations of alternative retail electric 
6suppliers.
7    (a) An alternative retail electric supplier:
8        (i) shall comply with the requirements imposed on 
9    public utilities by Sections 8-201 through 8-207, 8-301, 
10    8-505 and 8-507 of this Act, to the extent that these 
11    Sections have application to the services being offered by 
12    the alternative retail electric supplier;
13        (ii) shall continue to comply with the requirements 
14    for certification stated in subsection (d) of Section 
15    16-115;
16        (iii) by May 31, 2020 and every June 30 thereafter, 
17    shall submit to the Commission and the Office of the 
18    Attorney General the rates the retail electric supplier 
19    charged to residential customers in the prior year, 
20    including each distinct rate charged and whether the rate 
21    was a fixed or variable rate, the basis for the variable 
22    rate, and any fees charged in addition to the supply rate, 
23    including monthly fees, flat fees, or other service 
24    charges; and
25        (iv) shall make publicly available on its website, 
 
 
10400SB0025ham002- 724 -LRB104 07069 AAS 28576 a

1    without the need for a customer login, rate information 
2    for all of its variable, time-of-use, and fixed rate 
3    contracts currently available to residential customers, 
4    including, but not limited to, fixed monthly charges, 
5    early termination fees, and kilowatt-hour charges; .
6        (v) shall provide to the Commission, in the form and 
7    manner requested, the information necessary for the 
8    Commission to compile and submit the integrated resource 
9    plan required under Section 16-201; and
10        (vi) shall comply with the Commission's determinations 
11    made pursuant to subsection (b-10) of Section 16-111.5, 
12    including, but not limited to, the imposition of any 
13    collections, the execution of any contracts, and the 
14    required performance under any contracts developed 
15    thereunder.
16    (b) An alternative retail electric supplier shall obtain 
17verifiable authorization from a customer, in a form or manner 
18approved by the Commission consistent with Section 2EE of the 
19Consumer Fraud and Deceptive Business Practices Act, before 
20the customer is switched from another supplier.
21    (c) No alternative retail electric supplier, or electric 
22utility other than the electric utility in whose service area 
23a customer is located, shall (i) enter into or employ any 
24arrangements which have the effect of preventing a retail 
25customer with a maximum electrical demand of less than one 
26megawatt from having access to the services of the electric 
 
 
10400SB0025ham002- 725 -LRB104 07069 AAS 28576 a

1utility in whose service area the customer is located or (ii) 
2charge retail customers for such access. This subsection shall 
3not be construed to prevent an arms-length agreement between a 
4supplier and a retail customer that sets a term of service, 
5notice period for terminating service and provisions governing 
6early termination through a tariff or contract as allowed by 
7Section 16-119.
8    (d) An alternative retail electric supplier that is 
9certified to serve residential or small commercial retail 
10customers shall not:
11        (1) deny service to a customer or group of customers 
12    nor establish any differences as to prices, terms, 
13    conditions, services, products, facilities, or in any 
14    other respect, whereby such denial or differences are 
15    based upon race, gender or income, except as provided in 
16    Section 16-115E.
17        (2) deny service to a customer or group of customers 
18    based on locality nor establish any unreasonable 
19    difference as to prices, terms, conditions, services, 
20    products, or facilities as between localities.
21        (3) warrant that it has a residential customer or 
22    small commercial retail customer's express consent 
23    agreement to access interval data as described in 
24    subsection (b) of Section 16-122, unless the alternative 
25    retail electric supplier has:
26            (A) disclosed to the consumer at the outset of the 
 
 
10400SB0025ham002- 726 -LRB104 07069 AAS 28576 a

1        offer that the alternative retail electric supplier 
2        will access the consumer's interval data from the 
3        consumer's utility with the consumer's express 
4        agreement and the consumer's option to refuse to 
5        provide express agreement to access the consumer's 
6        interval data; and
7            (B) obtained the consumer's express agreement for 
8        the alternative retail electric supplier to access the 
9        consumer's interval data from the consumer's utility 
10        in a separate letter of agency, a distinct response to 
11        a third-party verification, or as a separate 
12        affirmative consent during a recorded enrollment 
13        initiated by the consumer. The disclosure by the 
14        alternative retail electric supplier to the consumer 
15        in this Section shall be conducted in, translated 
16        into, and provided in a language in which the consumer 
17        subject to the disclosure is able to understand and 
18        communicate.
19        (4) release, sell, license, or otherwise disclose any 
20    customer interval data obtained under Section 16-122 to 
21    any third person except as provided for in Section 16-122 
22    and paragraphs (1) through (4) of subsection (d-5) of 
23    Section 2EE of the Consumer Fraud and Deceptive Business 
24    Practices Act. 
25    (e) An alternative retail electric supplier shall comply 
26with the following requirements with respect to the marketing, 
 
 
10400SB0025ham002- 727 -LRB104 07069 AAS 28576 a

1offering and provision of products or services to residential 
2and small commercial retail customers:
3        (i) All marketing materials, including, but not 
4    limited to, electronic marketing materials, in-person 
5    solicitations, and telephone solicitations, shall contain 
6    information that adequately discloses the prices, terms, 
7    and conditions of the products or services that the 
8    alternative retail electric supplier is offering or 
9    selling to the customer and shall disclose the current 
10    utility electric supply price to compare applicable at the 
11    time the alternative retail electric supplier is offering 
12    or selling the products or services to the customer and 
13    shall disclose the date on which the utility electric 
14    supply price to compare became effective and the date on 
15    which it will expire. The utility electric supply price to 
16    compare shall be the sum of the electric supply charge and 
17    the transmission services charge and shall not include the 
18    purchased electricity adjustment. The disclosure shall 
19    include a statement that the price to compare does not 
20    include the purchased electricity adjustment, and, if 
21    applicable, the range of the purchased electricity 
22    adjustment. All marketing materials, including, but not 
23    limited to, electronic marketing materials, in-person 
24    solicitations, and telephone solicitations, shall include 
25    the following statement: 
26            "(Name of the alternative retail electric 
 
 
10400SB0025ham002- 728 -LRB104 07069 AAS 28576 a

1        supplier) is not the same entity as your electric 
2        delivery company. You are not required to enroll with 
3        (name of alternative retail electric supplier). 
4        Beginning on (effective date), the electric supply 
5        price to compare is (price in cents per kilowatt 
6        hour). The electric utility electric supply price will 
7        expire on (expiration date). The utility electric 
8        supply price to compare does not include the purchased 
9        electricity adjustment factor. For more information go 
10        to the Illinois Commerce Commission's free website at 
11        www.pluginillinois.org.
12        If applicable, the statement shall also include the 
13    following statement:
14            "The purchased electricity adjustment factor may 
15        range between +.5 cents and -.5 cents per kilowatt 
16        hour.". 
17        This paragraph (i) does not apply to goodwill or 
18    institutional advertising. 
19        (ii) Before any customer is switched from another 
20    supplier, the alternative retail electric supplier shall 
21    give the customer written information that adequately 
22    discloses, in plain language, the prices, terms and 
23    conditions of the products and services being offered and 
24    sold to the customer. This written information shall be 
25    provided in a language in which the customer subject to 
26    the marketing or solicitation is able to understand and 
 
 
10400SB0025ham002- 729 -LRB104 07069 AAS 28576 a

1    communicate, and the alternative retail electric supplier 
2    shall not switch a customer who is unable to understand 
3    and communicate in a language in which the marketing or 
4    solicitation was conducted. The alternative retail 
5    electric supplier shall comply with Section 2N of the 
6    Consumer Fraud and Deceptive Business Practices Act. 
7        (iii) An alternative retail electric supplier shall 
8    provide documentation to the Commission and to customers 
9    that substantiates any claims made by the alternative 
10    retail electric supplier regarding the technologies and 
11    fuel types used to generate the electricity offered or 
12    sold to customers.
13        (iv) The alternative retail electric supplier shall 
14    provide to the customer (1) itemized billing statements 
15    that describe the products and services provided to the 
16    customer and their prices, and (2) an additional 
17    statement, at least annually, that adequately discloses 
18    the average monthly prices, and the terms and conditions, 
19    of the products and services sold to the customer.
20        (v) All in-person and telephone solicitations shall be 
21    conducted in, translated into, and provided in a language 
22    in which the consumer subject to the marketing or 
23    solicitation is able to understand and communicate. An 
24    alternative retail electric supplier shall terminate a 
25    solicitation if the consumer subject to the marketing or 
26    communication is unable to understand and communicate in 
 
 
10400SB0025ham002- 730 -LRB104 07069 AAS 28576 a

1    the language in which the marketing or solicitation is 
2    being conducted. An alternative retail electric supplier 
3    shall comply with Section 2N of the Consumer Fraud and 
4    Deceptive Business Practices Act.
5        (vi) Each alternative retail electric supplier shall 
6    conduct training for individual representatives engaged in 
7    in-person solicitation and telemarketing to residential 
8    customers on behalf of that alternative retail electric 
9    supplier prior to conducting any such solicitations on the 
10    alternative retail electric supplier's behalf. Each 
11    alternative retail electric supplier shall submit a copy 
12    of its training material to the Commission on an annual 
13    basis and the Commission shall have the right to review 
14    and require updates to the material. After initial 
15    training, each alternative retail electric supplier shall 
16    be required to conduct refresher training for its 
17    individual representatives every 6 months. 
18    (f) An alternative retail electric supplier may limit the 
19overall size or availability of a service offering by 
20specifying one or more of the following: a maximum number of 
21customers, maximum amount of electric load to be served, time 
22period during which the offering will be available, or other 
23comparable limitation, but not including the geographic 
24locations of customers within the area which the alternative 
25retail electric supplier is certificated to serve. The 
26alternative retail electric supplier shall file the terms and 
 
 
10400SB0025ham002- 731 -LRB104 07069 AAS 28576 a

1conditions of such service offering including the applicable 
2limitations with the Commission prior to making the service 
3offering available to customers.
4    (g) Nothing in this Section shall be construed as 
5preventing an alternative retail electric supplier, which is 
6an affiliate of, or which contracts with, (i) an industry or 
7trade organization or association, (ii) a membership 
8organization or association that exists for a purpose other 
9than the purchase of electricity, or (iii) another 
10organization that meets criteria established in a rule adopted 
11by the Commission, from offering through the organization or 
12association services at prices, terms and conditions that are 
13available solely to the members of the organization or 
14association.
15(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
 
16    (220 ILCS 5/16-119A)
17    Sec. 16-119A. Functional separation. 
18    (a) Within 90 days after the effective date of this 
19amendatory Act of 1997, the Commission shall open a rulemaking 
20proceeding to establish standards of conduct for every 
21electric utility described in subsection (b). To create 
22efficient competition between suppliers of generating services 
23and sellers of such services at retail and wholesale, the 
24rules shall allow all customers of a public utility that 
25distributes electric power and energy to purchase electric 
 
 
10400SB0025ham002- 732 -LRB104 07069 AAS 28576 a

1power and energy from the supplier of their choice in 
2accordance with the provisions of Section 16-104. In addition, 
3the rules shall address relations between providers of any 2 
4services described in subsection (b) to prevent undue 
5discrimination and promote efficient competition. Provided, 
6however, that a proposed rule shall not be published prior to 
7May 15, 1999.
8    (b) The Commission shall also have the authority to 
9investigate the need for, and adopt rules requiring, 
10functional separation between the generation services and the 
11delivery services of those electric utilities whose principal 
12service area is in Illinois as necessary to meet the objective 
13of creating efficient competition between suppliers of 
14generating services and sellers of such services at retail and 
15wholesale. After January 1, 2003, the Commission shall also 
16have the authority to investigate the need for, and adopt 
17rules requiring, functional separation between an electric 
18utility's competitive and non-competitive services.
19    (b-5) If there is a change in ownership of a majority of 
20the voting capital stock of an electric utility or the 
21ownership or control of any entity that owns or controls a 
22majority of the voting capital stock of an electric utility, 
23the electric utility shall have the right to file with the 
24Commission a new plan. The newly filed plan shall supersede 
25any plan previously approved by the Commission pursuant to 
26this Section for that electric utility, subject to Commission 
 
 
10400SB0025ham002- 733 -LRB104 07069 AAS 28576 a

1approval. This subsection only applies to the extent that the 
2Commission rules for the functional separation of delivery 
3services and generation services provide an electric utility 
4with the ability to select from 2 or more options to comply 
5with this Section. The electric utility may file its revised 
6plan with the Commission up to one calendar year after the 
7conclusion of the sale, purchase, or any other transfer of 
8ownership described in this subsection. In all other respects, 
9an electric utility must comply with the Commission rules in 
10effect under this Section. The Commission may promulgate rules 
11to implement this subsection. This subsection shall have no 
12legal effect after January 1, 2005.
13    (c) In establishing or considering the need for rules 
14under subsections (a) and (b), the Commission shall take into 
15account the effects on the cost and reliability of service and 
16the obligation of the utility to provide bundled service under 
17this Act. The Commission shall adopt rules that are a cost 
18effective means to ensure compliance with this Section.
19    (d) Nothing in this Section shall be construed as imposing 
20any requirements or obligations that are in conflict with 
21federal law.
22    (e) Notwithstanding anything to the contrary, an electric 
23utility may market and promote the services, rates and 
24programs authorized by Sections 16-107, 16-107.8, and 16-108.6 
25of this Act.
26(Source: P.A. 99-906, eff. 6-1-17.)
 
 
 
10400SB0025ham002- 734 -LRB104 07069 AAS 28576 a

1    (220 ILCS 5/16-126.2 new)
2    Sec. 16-126.2. Energy Reliability Corporation of Illinois.
3    (a) The General Assembly finds that:
4        (1) When Illinois restructured its electric market in 
5    1997, Illinois' largest 2 electric utilities unexpectedly 
6    elected to join 2 different regional transmission 
7    organizations (RTO), which effectively split the State 
8    into 2 zones.
9        (2) In 2021, Illinois became the first state in the 
10    Midwest to mandate a clean energy future when it enacted 
11    the Climate and Equitable Jobs Act.
12        (3) Illinois' bifurcated, existing RTO membership 
13    structure has created significant concerns related to 
14    delays in transmission build out, excessively long 
15    interconnection queue processes, favoring polluting 
16    generation resources over more cost-effective clean 
17    sources, inhibiting State policies, and inexplicably 
18    frustrating State efforts to address its resource adequacy 
19    needs through the development of new generation.
20        (4) The governance structures of PJM Interconnection, 
21    LLC (PJM) and the Midcontinent Independent System 
22    Operator, Inc. (MISO) have consistently failed to 
23    represent Illinois' interests.
24        (5) The Illinois Commerce Commission is a trusted, 
25    neutral party with relevant expertise to evaluate and 
 
 
10400SB0025ham002- 735 -LRB104 07069 AAS 28576 a

1    present its findings related to the costs and benefits of 
2    Illinois establishing a single, State-specific Independent 
3    System Operator (ISO).
4        (6) The General Assembly intends to understand fully 
5    the effectiveness over time of creating such a single, 
6    State-specific ISO, including reducing ratepayer bills, 
7    supporting environmental and public health, and providing 
8    economic benefits to Illinois while creating good-paying 
9    jobs in equity communities, as well as for the members of 
10    organized labor. The potential benefits of a 
11    State-specific ISO may include, but are not limited to, 
12    support for Illinois' resource adequacy needs, grid 
13    reliability, reducing carbon and other pollutant 
14    emissions, stabilizing long-term and short-term electric 
15    rates, and supporting environmental justice communities, 
16    organized labor, job creation, and the overall economy.
17    (b) The Commission shall conduct and publish the findings 
18of a policy study to evaluate the effectiveness over time of 
19establishing a single State-operated ISO and to determine 
20whether such a move would be consistent with the State's goals 
21and would maximize benefits to State businesses and residents.
22    (c) The policy study shall evaluate the benefits and costs 
23of participation in MISO and PJM, including consideration of 
24the relative net benefits of participation in a State-specific 
25ISO. The study shall examine the costs and benefits of such 
26participation over 20 years. The study shall examine the costs 
 
 
10400SB0025ham002- 736 -LRB104 07069 AAS 28576 a

1and benefits to State ratepayers, including, but not limited 
2to, consideration of the regulatory, reliability, operational, 
3and competitive benefits of participating in MISO and PJM 
4versus a State-specific ISO. The costs and benefits evaluated 
5should include resource adequacy benefits, resilience, 
6affordability, equity, the impact on the environment, and the 
7general health, safety, and welfare of the People of the 
8State.
9    The study shall, at a minimum, include the following, and 
10it may consider or suggest additional or alternative items:
11        (1) the appropriate timetable to establish and 
12    effectively transition to a State-specific ISO, taking 
13    into account how that schedule could support the emission 
14    reduction timeline established in Section 9.15 of the 
15    Environmental Protection Act; and
16        (2) the appropriate benefits and costs to consider, 
17    such as the regulatory, reliability, operational, and 
18    competitive benefits, including, but not limited to:
19            (i) capacity market benefits and costs of 
20        separating from the PJM and MISO territories versus 
21        those of the status quo;
22            (ii) transmission benefits and costs of separating 
23        from the PJM and MISO territories versus those of a 
24        State-specific ISO;
25            (iii) the legal, correct, and appropriate exit 
26        fees for leaving regional transmission organizations;
 
 
10400SB0025ham002- 737 -LRB104 07069 AAS 28576 a

1            (iv) managing the State's energy resources to 
2        supply electricity throughout the State versus the 
3        existing bifurcated structure;
4            (v) the potential improvements in interconnection 
5        queue speed versus the current lengthy delays in the 
6        PJM and MISO processes;
7            (vi) the potential for a State-specific ISO to 
8        more effectively value and enable resources, such as 
9        storage of renewable resources, demand response, 
10        energy efficiency, and the adoption of new 
11        technologies and applications, versus the current PJM 
12        and MISO structures; and
13            (vii) an evaluation of any improved ability for 
14        the State to meet its goals and objectives in a new 
15        State-specific ISO versus the existing structure.
16        After the completion of the study, if the Commission 
17    finds that the results of the study were overall 
18    beneficial to the citizens of this State, then the 
19    Commission may conduct and publish an additional policy 
20    study 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 study 
23    regardless of the outcome of the original study.
24        The additional policy study shall investigate a 
25    governance structure and design that would enable State 
26    policy independence and more fully support State resource 
 
 
10400SB0025ham002- 738 -LRB104 07069 AAS 28576 a

1    adequacy and reliability while also complying with FERC 
2    Order 2000. The additional study may investigate how a 
3    State-specific ISO would be able to demonstrate the 
4    following issues, including, but not limited to:
5        (i) independence from market participants;
6        (ii) an appropriate scope and regional configuration;
7        (iii) possession of operational authority for all 
8    transmission facilities under the control of the 
9    State-specific ISO;
10        (iv) exclusive authority to maintain short-term 
11    reliability of the grid;
12        (v) tariff administration and design;
13        (vi) congestion management;
14        (vii) management of parallel path flows;
15        (viii) provision of last resort for ancillary 
16    services;
17        (ix) development of an Open Access Same-time 
18    Information System (OASIS);
19        (x) market monitoring; and
20        (xi) responsibility for planning and expanding 
21    facilities under its control.
22        The additional policy study shall also include an 
23    assessment of the appropriate entity and organizational 
24    structure and the staffing needs and physical needs of the 
25    independent organization, not-for-profit independent 
26    company, or State agency that would be tasked with 
 
 
10400SB0025ham002- 739 -LRB104 07069 AAS 28576 a

1    overseeing the State-specific ISO, including, but not 
2    limited to: (i) identifying the functions necessary for a 
3    State-specific ISO; (ii) attracting and retaining 
4    qualified staff; (iii) the engineering, design, or 
5    procurement of the physical facilities that would be 
6    required of a State-specific ISO; and (iv) the length of 
7    time it would reasonably take to establish a 
8    State-specific ISO in this State.
9    (d) The Commission shall retain the services of technical 
10and policy experts with relevant fields of expertise. Given 
11the critical and rapid actions required under this Section, 
12the Commission may procure the services of any facilitator, 
13expert, or consultant to assist with the implementation of 
14this Section. Such procurement is exempt from the requirements 
15of the Illinois Procurement Code under Section 20-10 of the 
16Illinois Procurement Code. The Commission may determine that 
17the cost of any contract pursuant to this Section may be borne 
18initially by the relevant electric public utilities, but shall 
19be recovered as an expense through normal ratemaking 
20procedures. The Illinois Power Agency, the Illinois Finance 
21Authority, the Illinois Environmental Protection Agency, and 
22the Department of Commerce and Economic Opportunity shall 
23provide support to and consult with the Commission when 
24requested. The Commission may consult with other State 
25agencies, commissions, or task forces as needed.
26    (e) The Commission may solicit information, including 
 
 
10400SB0025ham002- 740 -LRB104 07069 AAS 28576 a

1confidential or proprietary information, from entities likely 
2to be impacted by the creation of a State-specific ISO. The 
3Commission may consult with and seek assistance from (i) 
4Independent System Operators in other states, such as Texas, 
5California, and New York, (ii) federal agencies, such as the 
6Federal Energy Regulatory Commission, and (iii) the regional 
7transmission organizations PJM and MISO. Any information 
8designated as confidential or proprietary information by the 
9entity providing the information shall be kept confidential by 
10the Commission, its consultants, and its contractors and is 
11not subject to disclosure under the Freedom of Information 
12Act. The Office of the Attorney General shall have access to, 
13and maintain the confidentiality of, such information pursuant 
14to Section 6.5 of the Attorney General Act.
15    (f) The Commission shall publish its final policy study no 
16later than December 1, 2027 and suitable copies shall be 
17delivered to the Governor and members of the General Assembly.    
 
18    (220 ILCS 5/16-145 new)
19    Sec. 16-145. Powering Up Illinois.
20    (a) For the purposes of this Section:
21    "Electric utility" means an electric utility serving more 
22than 500,000 customers in this State.
23    "Energization" and "energize" means the connection of new 
24electric vehicle charging infrastructure projects over 5 
25megawatts to the electrical grid or upgrading electrical 
 
 
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1capacity to provide adequate service to such electric vehicle 
2charging infrastructure projects. "Energization" and 
3"energize" do not include activities related to connecting 
4electricity supply resources.
5    "Energization time period" means the period of time that 
6begins when the electric utility receives a substantially 
7complete energization project application and ends when the 
8electric service associated with the project is installed and 
9energized, consistent with the service obligations set forth 
10in the Section 8-101 of the Public Utilities Act.
11    (b) The Commission shall adopt rules to establish and 
12track reasonable average and maximum target energization time 
13periods for energization projects. Such rules shall, at a 
14minimum, establish the following:
15        (1) reasonable average and maximum target energization 
16    time periods. The targets shall ensure that work is 
17    completed in a safe and reliable manner that minimizes 
18    delay in meeting the date requested by a customer for 
19    completion of the energization project to the greatest 
20    extent possible. The targets may vary based on factors, 
21    including, but not limited to, customer class, size of the 
22    project, the complexity and magnitude of the work 
23    required, and uncertainties regarding the readiness of the 
24    customer project needing energization. The targets may 
25    also recognize any factors beyond the electric utility's 
26    control;
 
 
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1        (2) requirements for an electric utility to report to 
2    the Commission, at least annually, in order to track and 
3    improve electric utility performance. The report shall, at 
4    a minimum, include the average, median, and standard 
5    deviation time between receiving an application for 
6    electrical service and energizing the electrical service, 
7    and detailed explanations for energization time periods 
8    that exceed the target maximum for energization projects, 
9    constraints and obstacles to each type of energization, 
10    including, but not limited to, funding limitations, 
11    qualified staffing availability, or equipment 
12    availability, and any other information that the 
13    Commission, in its discretion, concludes that such reports 
14    should contain; and
15        (3) procedures for customers to report energization 
16    delays to the Commission.
17    (c) If an electric utility's average time period for 
18energization in a calendar year exceeds the Commission's 
19target averages or if an electric utility has exceeded the 
20Commission's target maximums as established by rule, the 
21electric utility shall include in its report pursuant to rules 
22adopted under paragraph (2) of subsection (b) a detailed 
23remedial plan for meeting the targets in the future. The 
24Commission may require modification to the electric utility's 
25remedial plan to ensure that the electric utility meets 
26targets promptly.
 
 
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1    (d) Data reported by electric utilities shall be 
2anonymized or aggregated to the extent necessary to prevent 
3identifying individual customers. The Commission shall make 
4all such reports publicly available.
5    (e) In addition to requiring remedial plans pursuant to 
6subsection (c) of this Section, the Commission may require an 
7electric utility to take any remedial actions necessary to 
8achieve the Commission's targets.    
 
9    (220 ILCS 5/16-201 new)
10    Sec. 16-201. Integrated resource plan development.
11    (a) The General Assembly hereby finds that:
12        (1) In 2021, Illinois set itself on the path to a clean 
13    energy future that would produce the least amount of 
14    carbon and copollutant emissions while ensuring adequate, 
15    reliable, affordable, efficient, and environmentally 
16    sustainable electric service at the lowest total cost over 
17    time and in a manner that benefits the Illinois economy 
18    and workforce and improves the quality of life, including 
19    environmental health, for all its citizens.
20        (2) In the ensuing years, Illinois has created a 
21    strong economic environment that has led to the 
22    revitalization and expansion of its manufacturing sector 
23    and has made Illinois an attractive place for the 
24    technology industry to locate new data and quantum 
25    computing centers. These developments have led to the 
 
 
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1    creation of good-paying jobs for working families.
2        (3) The unforeseen growth in the manufacturing and 
3    technology sectors will likely lead to a dramatic increase 
4    in electricity demand over time.
5        (4) The long interconnection times and the capacity 
6    market structures enacted by the 2 regional transmission 
7    organizations that Illinois is split between further 
8    exacerbate the potential for an imbalance between 
9    electricity supply and demand.
10        (5) The new sources of load growth from the 
11    manufacturing and technology sectors combined with 
12    external challenges require a more nimble and responsive 
13    administrative approach to effectively address future 
14    resource adequacy challenges.
15        (6) The Illinois agencies that oversee and implement 
16    Illinois energy policy must have the ability to (i) fully 
17    understand current and future resource adequacy needs, 
18    (ii) plan for what resources could be utilized to address 
19    such needs, (iii) be able to coordinate, modify, expand, 
20    and direct all of Illinois' existing energy programs and 
21    policies so as to address any resource adequacy or 
22    reliability concerns, and (iv) direct the development of 
23    new energy programs and policies in order meet resource 
24    adequacy and reliability needs without the need for 
25    additional legislative action.
26    (b) The purpose of this Section is to ensure that the 
 
 
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1Commission, the agencies, electric utilities supplying 
2electric service in Illinois, stakeholders, market 
3participants, and policymakers have a common set of data and 
4information regarding the State's electricity resource needs 
5in order to plan for sufficient electricity resources to serve 
6Illinois customers in a manner that is adequate, safe, 
7reliable, affordable, efficient, environmentally sustainable, 
8at the lowest cost over time, and consistent with the energy 
9policy goals of the State, including, but not limited to, the 
10clean energy policy established by Public Act 102-662. To that 
11end, this Section establishes a requirement that the agencies 
12prepare an integrated resource plan and submit such plan to 
13the Commission consistent with this Section for the 
14Commission's review and approval after an opportunity for 
15notice and hearing.
16    (c) Unless otherwise specified, as used in this Section, 
17the following terms shall have the following meanings:
18        (1) "Advanced transmission technologies" means 
19    technologies, tools, and software that improve power flows 
20    over transmission systems and lines. "Advanced 
21    transmission technologies" includes, but is not limited 
22    to, the following:
23            (i) technology that dynamically adjusts the rated 
24        capacity of transmission lines based on real-time 
25        conditions;
26            (ii) advanced power flow controls used to actively 
 
 
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1        control the flow of electricity across transmission 
2        lines to optimize usage or relieve congestion;
3            (iii) software or hardware used to identify 
4        optimal transmission grid configurations or enable 
5        routing power flows around congestion points; and
6            (iv) advanced transmission line conductors that 
7        have a direct current electrical resistance at least 
8        10% lower than existing conductors of a similar 
9        diameter on the transmission system.
10        (2) "Agencies" means the Illinois Commerce Commission 
11    Staff, the Illinois Power Agency, the Illinois Finance 
12    Authority, the Illinois Environmental Protection Agency, 
13    and any consultants those agencies retain, including, but 
14    not limited to, the consultant retained by the Commission 
15    pursuant to subsection (j) of this Section and the 
16    consultant retained by the Illinois Power Agency pursuant 
17    to paragraph (1) of subsection (a) of Section 1-75 of the 
18    Illinois Power Agency Act.
19        (3) "Clean energy" means energy generation that 
20    either:
21            (A) emits no on-site SO2, NOx, mercury, or any 
22        other regulated pollutants; or
23            (B) as shown through pollution control 
24        technologies, has reduced a utility's CO2 emissions by 
25        90% compared to what the utility would have otherwise 
26        emitted and that has CO2 emissions less than 130 
 
 
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1        lb/MWh.
2        (4) "Regional transmission organization" or "RTO" 
3    means PJM Interconnection, LLC (PJM) and the Midcontinent 
4    Independent System Operator, Inc. (MISO) or the regional 
5    transmission organization or independent system operator 
6    of which the electric utility is a member or would be a 
7    member, given the location of the electric utility's 
8    customers, if it were required to be a member.
9    (d) The agencies, coordinated by Commission staff, shall 
10compile and propose an integrated resource plan in compliance 
11with this Section once every 4 years. The agencies may consult 
12with each electric utility that has more than 500,000 electric 
13retail customers in developing the plan and the plan shall 
14consider any necessary interactions between RTO zones in the 
15State. Commission staff shall submit the initial integrated 
16resource plan to the Commission no later than December 31, 
172026, and subsequent plans shall be submitted every 4 years 
18thereafter, in each case by December 31 of the applicable 
19year. For the first integrated resource plan due on December 
2031, 2026, the agencies shall take into account the resource 
21adequacy report prepared pursuant to subsection (o) of Section 
229.15 of the Environmental Protection Act and shall 
23specifically address any and all divergences from the analysis 
24and conclusions in the report. At any time after the 
25submission of a plan, the agencies may submit an update to the 
26plan if the agencies believe that a material change in the 
 
 
10400SB0025ham002- 748 -LRB104 07069 AAS 28576 a

1inputs or conclusions of the plan is warranted. The agencies 
2shall notify the Commission as soon as practicable of the 
3material change and the potential update to the plan. The 
4Commission shall publish the integrated resource plan on its 
5website.
6    (e) An alternative retail electric supplier shall provide 
7information related to the resource needs of its customers 
8located in an electric utility's service territory as 
9requested by the agencies or the Commission to compile and 
10develop the plan required by this Section.
11    (f) Commission staff shall lead the agencies in the 
12development of the integrated resource plan to ensure that a 
13plan submitted pursuant to this Section includes a detailed 
14analysis of the following:
15        (1) an evaluation of the future electric resource 
16    needs in each electric utility's service area for periods 
17    of at least 5, 10, 15, and 20 years such that the plan 
18    coincides with the timelines established in Section 9.15 
19    of Title II of the Environmental Protection Act and is 
20    designed to support those standards to the maximum extent 
21    practicable on the schedule established therein;
22        (2) peak demand and energy usage forecasts, such that 
23    the plan:
24            (i) contains no fewer than 3 scenarios of (i) 
25        forecasted peak demand, (ii) net peak demand if 
26        different from peak demand, (iii) non-coincidental 
 
 
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1        peak demand, and (iv) energy usage, to capture a 
2        reasonable range of forecasts based on historic trends 
3        and a diverse range of more conservative to high load 
4        growth based on reasonable projections. The scenarios 
5        should consider estimates of peak demand corresponding 
6        to seasons or other applicable time periods as defined 
7        by the regional transmission organization in which 
8        this State's electric utilities are a member;
9            (ii) reflects known changes in facility and 
10        appliance codes and standards;
11            (iii) reflects load reductions from 
12        State-sponsored programs;
13            (iv) reflects load reductions from programs 
14        sponsored by electric utilities;
15            (v) reflects load reductions from aggregators of 
16        retail customers that can be applied to the host 
17        load-serving entity's resource adequacy requirement;
18            (vi) reflects load reductions from any other 
19        sources including out-of-state programs that could 
20        influence load;
21            (vii) reflects expected adoption of other 
22        distributed energy resources, including 
23        behind-the-meter generation; and
24            (viii) includes any additional sensitivities as 
25        determined by the agencies;
26        (3) an analysis of all generation and energy resource 
 
 
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1    options available to meet the range of load forecasts with 
2    a focus on the first period of at least 5 years covered by 
3    the plan, including an analysis of existing supply found 
4    within each electric utility's service area and new supply 
5    expected to come online across that period of at least 5 
6    years, such that the plan shall consider the following:
7            (i) the current and projected status of electric 
8        resource adequacy throughout the State from sources 
9        the agencies deem reasonable;
10            (ii) a range of resource options that can be 
11        deployed at a reasonable scale, that provide clean 
12        energy to the maximum extent practicable, and that 
13        include generation and energy resources on both the 
14        demand-side and supply-side;
15            (iii) developing technologies that will be 
16        commercially viable during the period of analysis;
17            (iv) reflect reasonable assumptions for capital 
18        and operating costs and the performance of resource 
19        technologies. The calculation of resource costs shall 
20        include reasonable expected costs for transmission 
21        interconnection and network upgrades made necessary by 
22        the addition of each resource; and
23            (v) appropriate considerations for implementation, 
24        such as:
25                (A) timelines for implementation, including, 
26            but not limited to, siting, permitting, 
 
 
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1            engineering, transmission interconnection, and the 
2            time it takes to modify existing programs or 
3            create new programs and put them into operation;
4                (B) recommendations for how new clean 
5            resources should be developed to respond to 
6            resource adequacy challenges; and
7                (C) any other requirements for implementation;
8        (4) confirmation that the resource adequacy and 
9    reliability requirements employed in the plan meet the 
10    following conditions:
11            (i) the plan must reflect planning reserve margin 
12        requirements established by the corresponding RTO, 
13        other resource adequacy requirements set by an 
14        applicable authority as authorized by the State, or 
15        another standard chosen by the Commission; and
16            (ii) the integrated resource plan may reflect a 
17        supplemental reliability analysis, including the 
18        evaluation of reliability metrics not prescribed by an 
19        RTO or other applicable authority as authorized by the 
20        State;
21        (5) consistency with existing State and federal 
22    environmental laws and policies, including, but not 
23    limited to, the decarbonization goals set forth in Section 
24    9.15 of the Illinois Environmental Protection Act. The 
25    plan may consider potential changes in State and federal 
26    environmental laws and policies. The plan must provide 
 
 
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1    expected emissions for CO2, SO2, NOx, mercury, and any 
2    other regulated pollutants in order to analyze the impact 
3    of retirement timelines on emissions reductions. The plan 
4    must be consistent with the State's other clean energy 
5    goals and targets, including, but not limited to, its 
6    renewable portfolio standard, its energy efficiency 
7    portfolio standard, the carbon mitigation credit program, 
8    and its energy storage system portfolio standard. The plan 
9    shall include an analysis of the following:
10            (i) the State's current progress toward its 
11        renewable energy resource development goals, its 
12        storage development goals, and its energy efficiency 
13        and demand-response goals, as well as the pace of the 
14        development of renewables, energy storage, including 
15        distributed storage, the deployment of virtual power 
16        plants, and demand-response utilization; and
17            (ii) the status of the State's CO2e and copollutant 
18        emissions reductions and its current status and 
19        progress toward developing emerging clean energy 
20        technologies;
21        (6) consideration of the following additional issues:
22            (i) an integrated resource plan shall be designed 
23        to collectively meet all of Illinois' energy policy 
24        goals and shall describe:
25                (A) how the plan complies with the various 
26            requirements of State energy policy;
 
 
10400SB0025ham002- 753 -LRB104 07069 AAS 28576 a

1                (B) the assumptions and analytical methods 
2            used in the plan;
3                (C) recommendations for how State policy 
4            should serve to facilitate the development of new 
5            resources;
6                (D) the impacts of the plan on customer costs, 
7            including net present value costs relative to 
8            alternatives; and
9                (E) how the plan improves energy equity within 
10            environmental justice and equity investment 
11            eligible communities, as defined by the Energy 
12            Transition Act, including, but not limited to, 
13            reducing energy burden, ensuring affordability of 
14            electric utility bills and uninterruptible 
15            essential utility service, and reducing barriers 
16            to accessing renewable energy;    
17            (ii) an integrated resource plan shall include a 
18        discussion of the steps needed to implement the plan, 
19        including, but not limited to, options and steps to 
20        bring on new or increased energy generated from any 
21        recommended resources for the 5 years after the plan 
22        would be implemented, that align with State clean 
23        energy policy;
24            (iii) an integrated resource plan shall consider 
25        the information and conclusions set forth in the 
26        renewable energy access plan developed in accordance 
 
 
10400SB0025ham002- 754 -LRB104 07069 AAS 28576 a

1        with Section 8-512, including, but not limited to, 
2        information concerning the locations of renewable 
3        energy access plan zones, considerations of advanced 
4        transmission technologies to increase efficiencies, 
5        and different transmission planning options and cost 
6        allocations;
7            (iv) an integrated resource plan may consider the 
8        impacts of future or anticipated changes in State and 
9        federal energy laws and policies; and
10            (v) any solutions for any additional conclusions;
11        (7) if the agencies choose, portfolio-optimization 
12    results based on the following:
13            (i) capacity expansion and production cost 
14        modeling consistent with the conditions and 
15        constraints set forth in this Section;
16            (ii) optimized candidate portfolios that align 
17        with the load-growth scenarios described in paragraph 
18        (2) of subsection (f) of this Section and any 
19        additional portfolios chosen by the agencies to 
20        reflect alternative policy or technology assumptions;
21            (iii) a comparison of total system cost on a 
22        net-present-value basis, customer rate and bill 
23        impacts, risk metrics, including, but not limited to, 
24        cost variability under fuel-price and load shocks, 
25        emissions trajectories, and key reliability 
26        indicators; and
 
 
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1            (iv) an identification of a preferred portfolio or 
2        portfolios that best satisfy the objectives of 
3        affordability, reliability, equity, and emission 
4        reduction and a narrative explanation of why the 
5        portfolio is recommended; and
6    The agencies may request that PJM and MISO, or their 
7respective successor organizations, conduct a resource 
8adequacy and reliability study. The study shall include the 
9megawatt amount of energy storage capacity that would maintain 
10resource adequacy during the study period to fully meet the 
11requirements for CO2e and copollutant emissions reductions 
12under Public Act 102-662 that would not otherwise be met by the 
13interconnection queue and without large transmission upgrades, 
14including maintaining sufficient in-State capacity to meet the 
15zonal requirements of MISO Zone 4 or the PJM ComEd Zone. The 
16study shall also identify recommended geographic locations for 
17new storage and clean energy to mitigate local reliability 
18risks, including at or near the sites of any generator 
19deactivations to maximize the efficient utilization of 
20existing infrastructure.    
 
21    (220 ILCS 5/16-202 new)
22    Sec. 16-202. Integrated resource plan review and approval.
23    (a) The Commission shall enter its order approving or 
24approving with modifications an integrated resource plan 
25within 180 days after the agencies filing the plan and any 
 
 
10400SB0025ham002- 756 -LRB104 07069 AAS 28576 a

1companion reports or other information. The Commission may 
2extend the period of review of the plan for no more than an 
3additional 180 days.
4    (b) The Commission may approve a plan or a modified plan 
5and authorize its implementation only if, after notice and 
6hearing, including the conduct of discovery and taking of 
7evidence, it finds that the plan:
8        (1) addresses any resource adequacy challenges in the 
9    5 years immediately following approval of the plan, while 
10    also taking into account the 10 years following the plan;
11        (2) prepares the State to best address issues of 
12    resource adequacy at the least amount of CO2e and 
13    copollutant emissions;
14        (3) considers the emissions' impacts on environmental 
15    justice communities while taking into account all 
16    applicable labor and equity standards;
17        (4) supports the provisioning of adequate, reliable, 
18    affordable, efficient, and environmentally sustainable 
19    electric service at the lowest total cost over time; and
20        (5) utilizes the expansion of renewable energy, energy 
21    storage, virtual power plants and distributed energy 
22    storage, energy efficiency, demand response, time-of-use 
23    rates or other mechanisms designed to manage peak load, 
24    transmission development, carbon mitigation credits or any 
25    other clean energy strategies to the maximum extent 
26    practicable to resolve any identified resource adequacy 
 
 
10400SB0025ham002- 757 -LRB104 07069 AAS 28576 a

1    shortfall or reliability violation in a cost-effective, 
2    affordable, timely, and clean manner.
3    (c) The Commission may, as a part of its decision to 
4approve a plan or modified plan and to the extent consistent 
5with the uniform allocation of costs required under subsection 
6(k) of Section 16-108, order changes to existing programs, 
7direct specific actions within existing programs including the 
8authorization to support the expansion of an existing program, 
9including, but not limited to:
10        (1) any of the following plans or programs designed to 
11    increase the amount of generation and capacity available:
12            (i) the Long-Term Renewable Resources Procurement 
13        Plan, including programs and procurements authorized 
14        through that Plan, and to increase the limitations 
15        placed on the procurement of renewable energy 
16        resources established pursuant to subparagraph (E) of 
17        paragraph (1) of subsection (c) of Section 1-75 of the 
18        Illinois Power Agency Act in order to increase, 
19        direct, or adjust procurements of renewable energy 
20        resources to support new renewable energy projects;
21            (ii) the Energy Storage Resources Procurement 
22        Plan, including programs and procurements authorized 
23        through that Plan, and to increase the procurement of 
24        energy storage established pursuant to subsection 
25        (d-20) of Section 1-75 of the Illinois Power Agency 
26        Act in order to increase or adjust procurements for 
 
 
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1        new energy storage;
2            (iii) the carbon mitigation credit procurement 
3        plans established pursuant to subsection (d-10) of 
4        Section 1-75 of the Illinois Power Agency Act in order 
5        to preserve existing carbon-free energy resources, 
6        including extending or expanding carbon mitigation 
7        credit contract awards in accordance with a new 
8        schedule of baseline costs;
9            (iv) the Illinois Power Agency's annual 
10        electricity procurement plans established pursuant to 
11        paragraph (2) of subsection (d) of Section 16-111.5, 
12        including modification of the products to be procured 
13        and allowing for costs associated with the purchase of 
14        new or additional products to be socialized across all 
15        retail customers or all load-serving entities, as 
16        applicable; and
17            (v) any additional programs designed to procure 
18        appropriate sources of new clean energy and capacity 
19        resources, including any associated clean attribute 
20        credits; and
21        (2) any of the following designed to manage energy 
22    demand, including, but not limited to:
23            (i) extending or expanding the energy efficiency 
24        programs implemented by electric utilities and the 
25        limitation on the amount of energy efficiency and 
26        demand-response measures implemented pursuant to 
 
 
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1        Section 8-103B in order to gain increased load 
2        reductions; and
3            (ii) the Multi-Year Integrated Grid Plans 
4        implemented by electric utilities pursuant to Section 
5        16-105.17 in order to extend or expand programs 
6        related to peak load management and reduction, 
7        including, but not limited to, virtual power plants, 
8        front of the meter distributed storage, demand 
9        response, and time-of-use rates.
10    (d) If all of the changes made to the programs pursuant to 
11this Section would reasonably be insufficient to balance 
12supply and demand and avoid a resource adequacy shortfall, 
13then the Commission may delay, in whole or in part, the CO2e    
14and copollutant emissions reductions requirements found in 
15Section 9.15 of the Environmental Protection Act but only to 
16the minimum extent and duration necessary to address the 
17resource adequacy shortfall needs of the State. If the 
18Commission finds that reducing or delaying the emissions 
19reductions requirements is necessary, despite any or all of 
20the changes made pursuant to this Section, then it shall also 
21include in its final order recommendations to the General 
22Assembly on what additional policies may be adopted that could 
23avoid future modifications to the emissions reductions.
24    (e) The agencies, electric utilities, and any other 
25impacted entities shall comply with any of the Commission's 
26orders, and when required seek approval from the Commission 
 
 
10400SB0025ham002- 760 -LRB104 07069 AAS 28576 a

1and make any required modifications to their plans, programs, 
2or related initiatives in a manner consistent with the process 
3and timing for those changes as outlined in the approved plans 
4or, if none is specified, as soon as practicable. If the 
5integrated resource plan approved by the Commission contains 
6recommendations that are outside the Commission's authority, 
7the Commission shall communicate any such recommendations to 
8the Governor and the General Assembly.
9    (f) Given the critical and rapid actions required under 
10this Section, the Commission may procure the services of any 
11facilitator, expert, or consultant, including the procurement 
12monitor retained by the Commission pursuant to paragraph (2) 
13of subsection (c) of Section 16-111.5. Such procurement is 
14exempt from the requirements of the Illinois Procurement Code, 
15pursuant to Section 20-10 of that Code.
16    (g) Costs that are prudently and reasonably incurred by 
17electric utilities to comply with the requirements of this 
18Section shall be recovered and shall be excluded from the 
19calculation performed under paragraph (6) of subsection (f) of 
20Section 16-108.18. Nothing in the Commission's order directing 
21changes to a prior approved plan as enumerated in this Section 
22shall be the sole basis for a finding of imprudence or 
23unreasonableness or the lack of use or usefulness of any 
24investment or expenditure.    
25    (h) The Commission may adopt rules to implement the 
26requirements of this Section.    
 
 
 
10400SB0025ham002- 761 -LRB104 07069 AAS 28576 a

1    (220 ILCS 5/17-900)
2    Sec. 17-900. Customer self-generation of electricity.
3    (a) The General Assembly finds and declares that municipal 
4systems and electric cooperatives shall continue to be 
5governed by their respective governing bodies, but that such 
6governing bodies should recognize and implement policies to 
7provide the opportunity for their residential and small 
8commercial customers who wish to self-generate electricity and 
9for reasonable credits to customers for excess electricity, 
10balanced against the rights of the other non-self-generating 
11customers. This includes creating consistent, fair policies 
12that are accessible to all customers and transparent, fair 
13processes for raising and addressing any concerns.
14    (b) Customers have the right to install renewable 
15generating facilities to be located on the customer's premises 
16or customer's side of the billing meter and that are intended 
17primarily to offset the customer's own electrical requirements 
18and produce, consume, and store their own renewable energy 
19without discriminatory repercussions from an electric 
20cooperative or municipal system. This includes a customer's 
21rights to:
22        (1) generate, consume, and deliver excess renewable 
23    energy to the distribution grid and reduce his or her use 
24    of electricity obtained from the grid;
25        (2) use technology to store energy at his or her 
 
 
10400SB0025ham002- 762 -LRB104 07069 AAS 28576 a

1    residence;
2        (3) interconnect his or her electrical system that 
3    generates renewable energy, stores energy, or any 
4    combination thereof, with the electricity meter on the 
5    customer's premises that is provided by an electric 
6    cooperative or municipal system:
7            (A) in a timely manner;
8            (B) in accordance with requirements established by 
9        the electric cooperative or municipal utility to 
10        ensure the safety of utility workers; and
11            (C) after providing written notice to the electric 
12        cooperative or municipal utility system providing 
13        service in the service territory, installing a 
14        nomenclature plate on the electrical meter panel and 
15        meeting all applicable State and local safety and 
16        electrical code requirements associated with 
17        installing a parallel distributed generation system; 
18        and
19        (4) receive fair credit for excess energy delivered to 
20    the distribution grid; and
21        (5) for residential and small commercial customers, 
22    interconnect renewable energy systems sized up to and 
23    including 25 kW AC.
24    (c) The policies of municipal systems and electric 
25cooperatives regarding self-generation and credits for excess 
26electricity may reasonably differ from those required of other 
 
 
10400SB0025ham002- 763 -LRB104 07069 AAS 28576 a

1entities by Article XVI of the Public Utilities Act or other 
2Acts. The credits must recognize the value of self-generation 
3to the distribution grid and benefits to other customers.
4    (c-5) The policies of municipal systems and electric 
5cooperatives regarding self-generation and credits for excess 
6electricity shall not require customers to name the municipal 
7system or electric cooperative as an additional insured on the 
8customer's insurance policies or have any minimum liability 
9limit requirement in connection with the installation and 
10operation of renewable generating facilities if the renewable 
11generating facilities meet the safety standards listed in the 
12applicable interconnection agreement and the contractor used 
13to install the renewable generating facilities is licensed and 
14possesses commercial general liability insurance coverage of 
15at least $1,000,000 per occurrence and $2,000,000 in the 
16aggregate per year.    
17    (d) Within 180 days after this amendatory Act of the 102nd 
18General Assembly, each electric cooperative and municipal 
19system shall update its policies for the interconnection and 
20fair crediting of customer self-generation and storage if 
21necessary, to comply with the standards of subsection (b) of 
22this Section. Each electric cooperative and municipal system 
23shall post its updated policies to a public-facing area of its 
24website.
25    (e) An electric cooperative or municipal system customer 
26who produces, consumes, and stores his or her own renewable 
 
 
10400SB0025ham002- 764 -LRB104 07069 AAS 28576 a

1energy shall not face discriminatory rate design, fees or 
2charges, treatment, or excessive compliance requirements that 
3would unreasonably affect that customer's right to 
4self-generate electricity as provided for in this Section.
5    (f) An electric cooperative or municipal utility system 
6customer shall have a right to appeal any decision related to 
7self-generation and storage that violates these rights to 
8self-generation and non-discrimination pursuant to the 
9provisions of this Section through a complaint under the 
10Administrative Review Law or similar legal process.
11(Source: P.A. 102-662, eff. 9-15-21.)
 
12    (220 ILCS 5/20-140 new)
13    Sec. 20-140. Interconnection Working Group.
14    (a) The Commission shall establish an Interconnection 
15Working Group. The Working Group shall include representatives 
16from electric utilities, developers of renewable electric 
17generating facilities, representatives of new large loads 
18seeking grid interconnection, other industries that regularly 
19apply for interconnection with the electric utilities as 
20appropriate, representatives of distributed generation 
21customers, the Commission staff, and other stakeholders with a 
22substantial interest in the topics addressed by the 
23Interconnection Working Group.
24    (b) The Interconnection Working Group shall address at 
25least the following issues in relation to new generation and 
 
 
10400SB0025ham002- 765 -LRB104 07069 AAS 28576 a

1new large loads:
2        (1) the cost of and the best available technology for 
3    interconnection and metering, including the 
4    standardization and publication of standard costs;
5        (2) transparency, accuracy, and use of the 
6    distribution interconnection queue and hosting capacity 
7    maps;
8        (3) distribution system upgrade cost avoidance through 
9    use of advanced inverter functions, energy storage, and 
10    load management;
11        (4) predictability of the queue management process and 
12    enforcement of timelines;
13        (5) benefits and challenges associated with group 
14    studies and cost sharing;
15        (6) minimum requirements for application to the 
16    interconnection process and throughout the interconnection 
17    process to avoid queue clogging behavior;
18        (7) the process and customer service for 
19    interconnecting customers adopting distributed energy 
20    resources, including energy storage;
21        (8) options for metering distributed energy resources, 
22    including energy storage;
23        (9) interconnection of new technologies, including 
24    smart inverters and energy storage;
25        (10) collection, examination, and sharing of data on 
26    Level 1 interconnection costs, including cost and type of 
 
 
10400SB0025ham002- 766 -LRB104 07069 AAS 28576 a

1    upgrades required for interconnection, and the use of this 
2    data to inform the final standardized cost of Level 1 
3    interconnection;
4        (11) determination of a single standardized cost for 
5    Level 1 interconnections, which shall not exceed $200; and
6        (12) such other technical, policy, and tariff issues 
7    related to and affecting interconnection performance and 
8    customer service as determined by the Interconnection 
9    Working Group.
10    (c) The Commission may create subcommittees of the 
11Interconnection Working Group to focus on specific issues of 
12importance, as appropriate.
13    (d) The Interconnection Working Group shall report to the 
14Commission on recommended improvements to interconnection 
15rules, tariffs, and policies as determined by the 
16Interconnection Working Group at least every year. A report 
17shall include consensus recommendations of the Interconnection 
18Working Group and, if applicable, additional recommendations 
19for which consensus was not reached. Non-consensus shall not 
20be a basis for excluding recommendations that are majority or 
21minority recommendations. The Commission shall use the report 
22from the Interconnection Working Group to determine whether 
23processes should be commenced to formally codify or implement 
24the recommendations. The Interconnection Working Group shall 
25provide the reports under this subsection (d) to the 
26Commission on at least the following topics in the order 
 
 
10400SB0025ham002- 767 -LRB104 07069 AAS 28576 a

1listed below within a reasonable time after the effective date 
2of this amendatory Act of the 104th General Assembly: (A) a 
3mechanism for good cause extensions to construction timelines 
4as long as the interconnection customer reasonably 
5demonstrates progress; (B) a mechanism for all electric 
6utilities to accept cash, letters of credit, or bonds for any 
7deposits required under the interconnection agreement; (C) 
8cost sharing for distribution system upgrades and 
9interconnection facilities for multiple interconnection 
10customers attempting to interconnect on the same feeder or 
11substation; and (D) requirements that interconnection studies 
12process without delay based on queue position or status of 
13applications ahead in the queue, and associated requirements 
14for disclosure of contingent upgrades.
15    (d-5) Within 12 months after the report directed by 
16subsection (d) has been submitted, the Working Group shall 
17report to the Commission on the following: (A) mandatory 
18disclosures on the hosting capacity map and studies for 
19contingent upgrades including timelines for notice of 
20responsibility and payment; and (B) a framework for concurrent 
21study on multiple feeders for a distributed energy resource.
22    (d-10) Within 12 months after the report directed by 
23subsection (d-5) has been submitted, the Working Group shall 
24report to the Commission on the following: (A) dynamic hosting 
25capacity maps; (B) standards for public queue and hosting 
26capacity map information regarding individual projects in 
 
 
10400SB0025ham002- 768 -LRB104 07069 AAS 28576 a

1queue, including (i) distributed generation nameplate 
2capacity, (ii) paired or stand-alone energy storage system 
3nameplate capacity, (iii) detailed estimated upgrade costs, 
4and (iv) systems that have completed upgrades and withdrawn 
5projects; and (C) timelines for refund of deposits if the 
6interconnection agreement is terminated. Within the same time 
7period, utilities shall publish all final interconnection 
8agreements, facilities studies, and system impact studies.
9    (d-15) Within 12 months after the report directed by 
10subsection (d-10) has been submitted, the Working Group shall 
11report to the Commission on the following: (A) level of detail 
12of costs in system impact and facilities studies and level 2 
13studies; and (B) a cap on charges to the interconnection 
14customer based on a percentage of the non-binding cost 
15estimate in the facilities study, system impact study, or 
16level 2 study.
17    (e) In collaboration with the General Counsel of the 
18Commission, the Office of Retail Market Development shall 
19develop policies and procedures to facilitate employees of the 
20Office in leading the Interconnection Working Group without 
21interference with docketed proceedings. The policies and 
22procedures developed under this subsection (e) shall be 
23designed to allow the Interconnection Working Group to work 
24without interruption.    
 
25    (220 ILCS 5/20-145 new)
 
 
10400SB0025ham002- 769 -LRB104 07069 AAS 28576 a

1    Sec. 20-145. Interconnection Monitor.
2    (a) The Office of Retail Market Development may employ, 
3designate, or otherwise retain the services of an Ombudsperson 
4who, in addition to the roles described in this Act, is 
5responsible for overseeing electric utility compliance with 
6the standards established by this Section and other regulatory 
7or statutory obligations regarding interconnections.
8    (b) The Ombudsperson may from time to time request, and 
9each electric utility shall timely provide records and 
10information to carry out his or her duties under this Section.
11    (c) The Office shall monitor interconnection between 
12electric utilities and applicants for interconnection and 
13interconnection customers. The Office may request, and 
14electric utilities shall promptly provide, information and 
15records related to pending, successful, and terminated 
16interconnections.
17    (d) The Office may require electric utilities to provide a 
18detailed breakdown of the non-binding costs of operation and 
19an estimate that transparently itemizes operational costs, 
20including equipment by type or model, labor, operation and 
21maintenance, engineering and design, permitting, easements and 
22rights-of-way, direct overhead, and indirect overhead.
23    (e) The Office may establish an informal interconnection 
24dispute resolution process that may supersede 83 Ill. Adm. 
25Code 466.130, 83 Ill. Adm. Code 467.80, and interconnection 
26agreements to the extent described in this subsection (e). 
 
 
10400SB0025ham002- 770 -LRB104 07069 AAS 28576 a

1Following the informal process described in this Section, 
2including any extensions agreed upon by the parties, an 
3electric utility, an interconnection customer, or an 
4interconnection applicant may submit the interconnection 
5dispute to the Ombudsperson, or his or her designee. The 
6Ombudsperson, or his or her designee, shall provide a 
7recommended resolution of such dispute within 30 days after 
8the Ombudsperson determines that full information from all 
9parties to the dispute has been received. The electric 
10utility, the interconnection customer, the interconnection 
11applicant, or any other party authorized to initiate dispute 
12resolution under the Commission's rules authorized by this Act 
13may include the Ombudsperson's recommendation in any formal 
14complaint before the Commission.
15    (f) The Office is encouraged to include at least one 
16employee, at the Bureau Chief's discretion, with a background 
17in engineering of renewable resources and distribution 
18interconnections.    
 
19    Section 90-40. The Electric Transmission Systems 
20Construction Standards Act is amended by changing Sections 5 
21and 15 as follows:
 
22    (220 ILCS 32/5)
23    Sec. 5. Definitions. For the purposes of this Act:
24    "Commission" means the Illinois Commerce Commission. 
 
 
10400SB0025ham002- 771 -LRB104 07069 AAS 28576 a

1    "Construction contractor" means any nonutility entity 
2responsible for the construction, installation, maintenance, 
3or repair of electric transmission systems subject to this 
4Act.
5    "Electric transmission systems" means an electrical 
6transmission system designed and constructed with the 
7capability of being safely and reliably energized at 69 
8kilovolts or more, including transmission lines, transmission 
9towers, conductors, insulators, foundations, grounding 
10systems, access roads, and all associated transmission 
11facilities, including transmission substations. "Electric 
12transmission systems" does not include projects located on the 
13electric generating facility's side of the facility's point of 
14interconnection or facilities not functionally classified as 
15transmission systems, regardless of voltage.
16    "OSHA" means Occupational Safety and Health 
17Administration.
18    "Utility" means an entity that is a public utility, as 
19defined in Section 3-105 of the Public Utilities Act, and that 
20serves residential customers. has the meaning given to that 
21term in Section 3-105 of the Public Utilities Act.
22(Source: P.A. 103-1066, eff. 2-20-25.)
 
23    (220 ILCS 32/15)
24    Sec. 15. Requirements for construction contractors.
25    (a) Prevailing wage compliance. All utilities and    
 
 
10400SB0025ham002- 772 -LRB104 07069 AAS 28576 a

1construction contractors responsible for the construction, 
2installation, maintenance, or repair of electric transmission 
3systems shall pay employees performing the construction, 
4installation, maintenance, or repair work of such systems 
5wages and benefits consistent with the Prevailing Wage Act.
6    (b) Training and competence requirement. To ensure safety 
7and reliability in the construction, installation, 
8maintenance, and repair of electric transmission systems, each 
9electric utility and construction contractor must demonstrate 
10the competence of their employees who are performing the work 
11of construction, installation, maintenance, or repair of 
12electric transmission systems, which shall be consistent with 
13the standards required by Illinois utilities as of January 1, 
142007, or greater. Competence must include, at a minimum: (1) 
15completion, or active participation with ultimate completion, 
16in an accredited or recognized apprenticeship program for the 
17relevant craft, trade, or skill; or (2) a minimum of 2 years of 
18direct employment in the specific work function. 
19    The Commission shall oversee compliance to ensure 
20employees meet these standards.
21    (c) Safety training. All employees engaged in the 
22construction, installation, maintenance, or repair of electric 
23transmission systems must successfully complete OSHA-certified 
24safety training required for their specific roles on the 
25project site.
26    (d) Diversity Plan.
 
 
10400SB0025ham002- 773 -LRB104 07069 AAS 28576 a

1        (1) All construction contractors engaged in the 
2    construction, installation, maintenance, or repair of 
3    electric transmission systems shall develop a Diversity 
4    Plan that sets forth:
5            (A) the goals for apprenticeship hours to be 
6        performed by minorities and women;
7            (B) the goals for total hours to be performed by 
8        underrepresented minorities and women; and
9            (C) spending for women-owned, minority-owned, 
10        veteran-owned, and small business enterprises in the 
11        previous calendar year.
12        (2) These goals shall be expressed as a percentage of 
13    the total work performed by the construction contractor 
14    submitting the plan and the actual spending for all 
15    women-owned, minority-owned, veteran-owned, and small 
16    business enterprises shall also be expressed as a 
17    percentage of the total work performed by the construction 
18    contractor submitting the Diversity Plan.
19        (3) For purposes of the Diversity Plan, minorities and 
20    women shall have the same definition as defined in the 
21    Business Enterprise for Minorities, Women, and Persons 
22    with Disabilities Act.
23        (4) The construction contractor shall submit the 
24    Diversity Plan to the Commission.
25(Source: P.A. 103-1066, eff. 2-20-25.)
 
 
 
10400SB0025ham002- 774 -LRB104 07069 AAS 28576 a

1    Section 90-45. The Environmental Protection Act is amended 
2by changing Sections 9.15 and 39 as follows:
 
3    (415 ILCS 5/9.15)
4    Sec. 9.15. Greenhouse gases.
5    (a) An air pollution construction permit shall not be 
6required due to emissions of greenhouse gases if the 
7equipment, site, or source is not subject to regulation, as 
8defined by 40 CFR 52.21, as now or hereafter amended, for 
9greenhouse gases or is otherwise not addressed in this Section 
10or by the Board in regulations for greenhouse gases. These 
11exemptions do not relieve an owner or operator from the 
12obligation to comply with other applicable rules or 
13regulations.
14    (b) An air pollution operating permit shall not be 
15required due to emissions of greenhouse gases if the 
16equipment, site, or source is not subject to regulation, as 
17defined by Section 39.5 of this Act, for greenhouse gases or is 
18otherwise not addressed in this Section or by the Board in 
19regulations for greenhouse gases. These exemptions do not 
20relieve an owner or operator from the obligation to comply 
21with other applicable rules or regulations.
22    (c) (Blank). 
23    (d) (Blank).
24    (e) (Blank). 
25    (f) As used in this Section:
 
 
10400SB0025ham002- 775 -LRB104 07069 AAS 28576 a

1    "Carbon dioxide emission" means the plant annual CO2 total 
2output emission as measured by the United States Environmental 
3Protection Agency in its Emissions & Generation Resource 
4Integrated Database (eGrid), or its successor. 
5    "Carbon dioxide equivalent emissions" or "CO2e" means the 
6sum total of the mass amount of emissions in tons per year, 
7calculated by multiplying the mass amount of each of the 6 
8greenhouse gases specified in Section 3.207, in tons per year, 
9by its associated global warming potential as set forth in 40 
10CFR 98, subpart A, table A-1 or its successor, and then adding 
11them all together.
12    "Cogeneration" or "combined heat and power" refers to any 
13system that, either simultaneously or sequentially, produces 
14electricity and useful thermal energy from a single fuel 
15source.
16    "Copollutants" refers to the 6 criteria pollutants that 
17have been identified by the United States Environmental 
18Protection Agency pursuant to the Clean Air Act.
19    "Electric generating unit" or "EGU" means a fossil 
20fuel-fired stationary boiler, combustion turbine, or combined 
21cycle system that serves a generator that has a nameplate 
22capacity greater than 25 MWe and produces electricity for 
23sale.
24    "Environmental justice community" means the definition of 
25that term based on existing methodologies and findings, used 
26and as may be updated by the Illinois Power Agency and its 
 
 
10400SB0025ham002- 776 -LRB104 07069 AAS 28576 a

1program administrator in the Illinois Solar for All Program.
2    "Equity investment eligible community" or "eligible 
3community" means the geographic areas throughout Illinois that 
4would most benefit from equitable investments by the State 
5designed to combat discrimination and foster sustainable 
6economic growth. Specifically, eligible community means the 
7following areas:
8        (1) areas where residents have been historically 
9    excluded from economic opportunities, including 
10    opportunities in the energy sector, as defined as R3 areas 
11    pursuant to Section 10-40 of the Cannabis Regulation and 
12    Tax Act; and
13        (2) areas where residents have been historically 
14    subject to disproportionate burdens of pollution, 
15    including pollution from the energy sector, as established 
16    by environmental justice communities as defined by the 
17    Illinois Power Agency pursuant to the Illinois Power 
18    Agency Act, excluding any racial or ethnic indicators.
19    "Equity investment eligible person" or "eligible person" 
20means the persons who would most benefit from equitable 
21investments by the State designed to combat discrimination and 
22foster sustainable economic growth. Specifically, eligible 
23person means the following people:
24        (1) persons whose primary residence is in an equity 
25    investment eligible community;
26        (2) persons whose primary residence is in a 
 
 
10400SB0025ham002- 777 -LRB104 07069 AAS 28576 a

1    municipality, or a county with a population under 100,000, 
2    where the closure of an electric generating unit or mine 
3    has been publicly announced or the electric generating 
4    unit or mine is in the process of closing or closed within 
5    the last 5 years;
6        (3) persons who are graduates of or currently enrolled 
7    in the foster care system; or
8        (4) persons who were formerly incarcerated.
9    "Existing emissions" means: 
10        (1) for CO2e, the total average tons-per-year of CO2e 
11    emitted by the EGU or large GHG-emitting unit either in 
12    the years 2018 through 2020 or, if the unit was not yet in 
13    operation by January 1, 2018, in the first 3 full years of 
14    that unit's operation; and
15        (2) for any copollutant, the total average 
16    tons-per-year of that copollutant emitted by the EGU or 
17    large GHG-emitting unit either in the years 2018 through 
18    2020 or, if the unit was not yet in operation by January 1, 
19    2018, in the first 3 full years of that unit's operation. 
20    "Green hydrogen" means a power plant technology in which 
21an EGU creates electric power exclusively from electrolytic 
22hydrogen, in a manner that produces zero carbon and 
23copollutant emissions, using hydrogen fuel that is 
24electrolyzed using a 100% renewable zero carbon emission 
25energy source.
26    "Large greenhouse gas-emitting unit" or "large 
 
 
10400SB0025ham002- 778 -LRB104 07069 AAS 28576 a

1GHG-emitting unit" means a unit that is an electric generating 
2unit or other fossil fuel-fired unit that itself has a 
3nameplate capacity or serves a generator that has a nameplate 
4capacity greater than 25 MWe and that produces electricity, 
5including, but not limited to, coal-fired, coal-derived, 
6oil-fired, natural gas-fired, and cogeneration units.
7    "NOx emission rate" means the plant annual NOx total output 
8emission rate as measured by the United States Environmental 
9Protection Agency in its Emissions & Generation Resource 
10Integrated Database (eGrid), or its successor, in the most 
11recent year for which data is available.
12    "Public greenhouse gas-emitting units" or "public 
13GHG-emitting unit" means large greenhouse gas-emitting units, 
14including EGUs, that are wholly owned, directly or indirectly, 
15by one or more municipalities, municipal corporations, joint 
16municipal electric power agencies, electric cooperatives, or 
17other governmental or nonprofit entities, whether organized 
18and created under the laws of Illinois or another state.
19    "SO2 emission rate" means the "plant annual SO2 total 
20output emission rate" as measured by the United States 
21Environmental Protection Agency in its Emissions & Generation 
22Resource Integrated Database (eGrid), or its successor, in the 
23most recent year for which data is available.
24    (g) All EGUs and large greenhouse gas-emitting units that 
25use coal or oil as a fuel and are not public GHG-emitting units 
26shall permanently reduce all CO2e and copollutant emissions to 
 
 
10400SB0025ham002- 779 -LRB104 07069 AAS 28576 a

1zero no later than January 1, 2030.
2    (h) All EGUs and large greenhouse gas-emitting units that 
3use coal as a fuel and are public GHG-emitting units shall 
4permanently reduce CO2e emissions to zero no later than 
5December 31, 2045. Any source or plant with such units must 
6also reduce their CO2e emissions by 45% from existing 
7emissions by no later than January 1, 2035. If the emissions 
8reduction requirement is not achieved by December 31, 2035, 
9the plant shall retire one or more units or otherwise reduce 
10its CO2e emissions by 45% from existing emissions by June 30, 
112038.
12    (i) All EGUs and large greenhouse gas-emitting units that 
13use gas as a fuel and are not public GHG-emitting units shall 
14permanently reduce all CO2e and copollutant emissions to zero, 
15including through unit retirement or the use of 100% green 
16hydrogen or other similar technology that is commercially 
17proven to achieve zero carbon emissions, according to the 
18following:
19        (1) No later than January 1, 2030: all EGUs and large 
20    greenhouse gas-emitting units that have a NOx emissions 
21    rate of greater than 0.12 lbs/MWh or a SO2 emission rate of 
22    greater than 0.006 lb/MWh, and are located in or within 3 
23    miles of an environmental justice community designated as 
24    of January 1, 2021 or an equity investment eligible 
25    community.
26        (2) No later than January 1, 2040: all EGUs and large 
 
 
10400SB0025ham002- 780 -LRB104 07069 AAS 28576 a

1    greenhouse gas-emitting units that have a NOx emission 
2    rate of greater than 0.12 lbs/MWh or a SO2 emission rate 
3    greater than 0.006 lb/MWh, and are not located in or 
4    within 3 miles of an environmental justice community 
5    designated as of January 1, 2021 or an equity investment 
6    eligible community. After January 1, 2035, each such EGU 
7    and large greenhouse gas-emitting unit shall reduce its 
8    CO2e emissions by at least 50% from its existing emissions 
9    for CO2e, and shall be limited in operation to, on average, 
10    6 hours or less per day, measured over a calendar year, and 
11    shall not run for more than 24 consecutive hours except in 
12    emergency conditions, as designated by a Regional 
13    Transmission Organization or Independent System Operator.
14        (3) No later than January 1, 2035: all EGUs and large 
15    greenhouse gas-emitting units that began operation prior 
16    to the effective date of this amendatory Act of the 102nd 
17    General Assembly and have a NOx emission rate of less than 
18    or equal to 0.12 lb/MWh and a SO2 emission rate less than 
19    or equal to 0.006 lb/MWh, and are located in or within 3 
20    miles of an environmental justice community designated as 
21    of January 1, 2021 or an equity investment eligible 
22    community. Each such EGU and large greenhouse gas-emitting 
23    unit shall reduce its CO2e emissions by at least 50% from 
24    its existing emissions for CO2e no later than January 1, 
25    2030.
26        (4) No later than January 1, 2040: All remaining EGUs 
 
 
10400SB0025ham002- 781 -LRB104 07069 AAS 28576 a

1    and large greenhouse gas-emitting units that have a heat 
2    rate greater than or equal to 7000 BTU/kWh. Each such EGU 
3    and Large greenhouse gas-emitting unit shall reduce its 
4    CO2e emissions by at least 50% from its existing emissions 
5    for CO2e no later than January 1, 2035.
6        (5) No later than January 1, 2045: all remaining EGUs 
7    and large greenhouse gas-emitting units. 
8    (j) All EGUs and large greenhouse gas-emitting units that 
9use gas as a fuel and are public GHG-emitting units shall 
10permanently reduce all CO2e and copollutant emissions to zero, 
11including through unit retirement or the use of 100% green 
12hydrogen or other similar technology that is commercially 
13proven to achieve zero carbon emissions by January 1, 2045.
14    (k) All EGUs and large greenhouse gas-emitting units that 
15utilize combined heat and power or cogeneration technology 
16shall permanently reduce all CO2e and copollutant emissions to 
17zero, including through unit retirement or the use of 100% 
18green hydrogen or other similar technology that is 
19commercially proven to achieve zero carbon emissions by 
20January 1, 2045.
21    (k-5) No EGU or large greenhouse gas-emitting unit that 
22uses gas as a fuel and is not a public GHG-emitting unit may 
23emit, in any 12-month period, CO2e or copollutants in excess of 
24that unit's existing emissions for those pollutants. 
25    (l) Notwithstanding subsections (g) through (k-5), large 
26GHG-emitting units including EGUs may temporarily continue 
 
 
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1emitting CO2e and copollutants after any applicable deadline 
2specified in any of subsections (g) through (k-5) if it has 
3been determined, as described in paragraphs (1) and (2) of 
4this subsection, that ongoing operation of the EGU is 
5necessary to maintain power grid supply and reliability or 
6ongoing operation of large GHG-emitting unit that is not an 
7EGU is necessary to serve as an emergency backup to 
8operations. Up to and including the occurrence of an emission 
9reduction deadline under subsection (i), all EGUs and large 
10GHG-emitting units must comply with the following terms:
11        (1) if an EGU or large GHG-emitting unit that is a 
12    participant in a regional transmission organization 
13    intends to retire, it must submit documentation to the 
14    appropriate regional transmission organization by the 
15    appropriate deadline that meets all applicable regulatory 
16    requirements necessary to obtain approval to permanently 
17    cease operating the large GHG-emitting unit;
18        (2) if any EGU or large GHG-emitting unit that is a 
19    participant in a regional transmission organization 
20    receives notice that the regional transmission 
21    organization has determined that continued operation of 
22    the unit is required, the unit may continue operating 
23    until the issue identified by the regional transmission 
24    organization is resolved. The owner or operator of the 
25    unit must cooperate with the regional transmission 
26    organization in resolving the issue and must reduce its 
 
 
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1    emissions to zero, consistent with the requirements under 
2    subsection (g), (h), (i), (j), (k), or (k-5), as 
3    applicable, as soon as practicable when the issue 
4    identified by the regional transmission organization is 
5    resolved; and
6        (3) any large GHG-emitting unit that is not a 
7    participant in a regional transmission organization shall 
8    be allowed to continue emitting CO2e and copollutants 
9    after the zero-emission date specified in subsection (g), 
10    (h), (i), (j), (k), or (k-5), as applicable, in the 
11    capacity of an emergency backup unit if approved by the 
12    Illinois Commerce Commission.
13    (m) No variance, adjusted standard, or other regulatory 
14relief otherwise available in this Act may be granted to the 
15emissions reduction and elimination obligations in this 
16Section.
17    (n) By June 30 of each year, beginning in 2025, the Agency 
18shall prepare and publish on its website a report setting 
19forth the actual greenhouse gas emissions from individual 
20units and the aggregate statewide emissions from all units for 
21the prior year.
22    (o) The Every 5 years beginning in 2025, the Environmental 
23Protection Agency, Illinois Power Agency, and Illinois 
24Commerce Commission shall jointly prepare, and release 
25publicly, a report to the General Assembly that examines the 
26State's current progress toward its renewable energy resource 
 
 
10400SB0025ham002- 784 -LRB104 07069 AAS 28576 a

1development goals, the status of CO2e and copollutant 
2emissions reductions, the current status and progress toward 
3developing and implementing green hydrogen technologies, the 
4current and projected status of electric resource adequacy and 
5reliability throughout the State for the period beginning 5 
6years ahead, and proposed solutions for any findings. The 
7Environmental Protection Agency, Illinois Power Agency, and 
8Illinois Commerce Commission shall consult PJM 
9Interconnection, LLC and Midcontinent Independent System 
10Operator, Inc., or their respective successor organizations 
11regarding forecasted resource adequacy and reliability needs, 
12anticipated new generation interconnection, new transmission 
13development or upgrades, and any announced large GHG-emitting 
14unit closure dates and include this information in the report. 
15The report shall be released publicly by no later than 
16December 15, 2025 or the effective date of this amendatory Act 
17of the 104th General Assembly, whichever is later of the year 
18it is prepared. If the Environmental Protection Agency, 
19Illinois Power Agency, and Illinois Commerce Commission 
20jointly conclude in the report that the data from the regional 
21grid operators, the pace of renewable energy development, the 
22pace of development of energy storage and demand response 
23utilization, transmission capacity, and the CO2e and 
24copollutant emissions reductions required by subsection (i) or 
25(k-5) reasonably demonstrate that a resource adequacy 
26shortfall will occur, including whether there will be 
 
 
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1sufficient in-state capacity to meet the zonal requirements of 
2MISO Zone 4 or the PJM ComEd Zone, per the requirements of the 
3regional transmission organizations, or that the regional 
4transmission operators determine that a reliability violation 
5will occur during the time frame the study is evaluating, then 
6the Illinois Power Agency, in conjunction with the 
7Environmental Protection Agency shall develop a plan to reduce 
8or delay CO2e and copollutant emissions reductions 
9requirements only to the extent and for the duration necessary 
10to meet the resource adequacy and reliability needs of the 
11State, including allowing any plants whose emission reduction 
12deadline has been identified in the plan as creating a 
13reliability concern to continue operating, including operating 
14with reduced emissions or as emergency backup where 
15appropriate. The plan shall also consider the use of renewable 
16energy, energy storage, demand response, transmission 
17development, or other strategies to resolve the identified 
18resource adequacy shortfall or reliability violation.
19        (1) In developing the plan, the Environmental 
20    Protection Agency and the Illinois Power Agency shall hold 
21    at least one workshop open to, and accessible at a time and 
22    place convenient to, the public and shall consider any 
23    comments made by stakeholders or the public. Upon 
24    development of the plan, copies of the plan shall be 
25    posted and made publicly available on the Environmental 
26    Protection Agency's, the Illinois Power Agency's, and the 
 
 
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1    Illinois Commerce Commission's websites. All interested 
2    parties shall have 60 days following the date of posting 
3    to provide comment to the Environmental Protection Agency 
4    and the Illinois Power Agency on the plan. All comments 
5    submitted to the Environmental Protection Agency and the 
6    Illinois Power Agency shall be encouraged to be specific, 
7    supported by data or other detailed analyses, and, if 
8    objecting to all or a portion of the plan, accompanied by 
9    specific alternative wording or proposals. All comments 
10    shall be posted on the Environmental Protection Agency's, 
11    the Illinois Power Agency's, and the Illinois Commerce 
12    Commission's websites. Within 30 days following the end of 
13    the 60-day review period, the Environmental Protection 
14    Agency and the Illinois Power Agency shall revise the plan 
15    as necessary based on the comments received and file its 
16    revised plan with the Illinois Commerce Commission for 
17    approval.
18        (2) Within 60 days after the filing of the revised 
19    plan at the Illinois Commerce Commission, any person 
20    objecting to the plan shall file an objection with the 
21    Illinois Commerce Commission. Within 30 days after the 
22    expiration of the comment period, the Illinois Commerce 
23    Commission shall determine whether an evidentiary hearing 
24    is necessary. The Illinois Commerce Commission shall also 
25    host 3 public hearings within 90 days after the plan is 
26    filed. Following the evidentiary and public hearings, the 
 
 
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1    Illinois Commerce Commission shall enter its order 
2    approving or approving with modifications the reliability 
3    mitigation plan within 180 days.
4        (3) The Illinois Commerce Commission shall only 
5    approve the plan if the Illinois Commerce Commission 
6    determines that it will resolve the resource adequacy or 
7    reliability deficiency identified in the reliability 
8    mitigation plan at the least amount of CO2e and copollutant 
9    emissions, taking into consideration the emissions impacts 
10    on environmental justice communities, and that it will 
11    ensure adequate, reliable, affordable, efficient, and 
12    environmentally sustainable electric service at the lowest 
13    total cost over time, taking into account the impact of 
14    increases in emissions.
15        (4) If the resource adequacy or reliability deficiency 
16    identified in the reliability mitigation plan is resolved 
17    or reduced, the Environmental Protection Agency and the 
18    Illinois Power Agency may file an amended plan adjusting 
19    the reduction or delay in CO2e and copollutant emission 
20    reduction requirements identified in the plan. 
21(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
 
22    (415 ILCS 5/39)  (from Ch. 111 1/2, par. 1039)
23    Sec. 39. Issuance of permits; procedures. 
24    (a) When the Board has by regulation required a permit for 
25the construction, installation, or operation of any type of 
 
 
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1facility, equipment, vehicle, vessel, or aircraft, the 
2applicant shall apply to the Agency for such permit and it 
3shall be the duty of the Agency to issue such a permit upon 
4proof by the applicant that the facility, equipment, vehicle, 
5vessel, or aircraft will not cause a violation of this Act or 
6of regulations hereunder. The Agency shall adopt such 
7procedures as are necessary to carry out its duties under this 
8Section. In making its determinations on permit applications 
9under this Section the Agency may consider prior adjudications 
10of noncompliance with this Act by the applicant that involved 
11a release of a contaminant into the environment. In granting 
12permits, the Agency may impose reasonable conditions 
13specifically related to the applicant's past compliance 
14history with this Act as necessary to correct, detect, or 
15prevent noncompliance. The Agency may impose such other 
16conditions as may be necessary to accomplish the purposes of 
17this Act, and as are not inconsistent with the regulations 
18promulgated by the Board hereunder. Except as otherwise 
19provided in this Act, a bond or other security shall not be 
20required as a condition for the issuance of a permit. If the 
21Agency denies any permit under this Section, the Agency shall 
22transmit to the applicant within the time limitations of this 
23Section specific, detailed statements as to the reasons the 
24permit application was denied. Such statements shall include, 
25but not be limited to, the following:
26        (i) the Sections of this Act which may be violated if 
 
 
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1    the permit were granted;
2        (ii) the provision of the regulations, promulgated 
3    under this Act, which may be violated if the permit were 
4    granted;
5        (iii) the specific type of information, if any, which 
6    the Agency deems the applicant did not provide the Agency; 
7    and
8        (iv) a statement of specific reasons why the Act and 
9    the regulations might not be met if the permit were 
10    granted.
11    If there is no final action by the Agency within 90 days 
12after the filing of the application for permit, the applicant 
13may deem the permit issued; except that this time period shall 
14be extended to 180 days when (1) notice and opportunity for 
15public hearing are required by State or federal law or 
16regulation, (2) the application which was filed is for any 
17permit to develop a landfill subject to issuance pursuant to 
18this subsection, or (3) the application that was filed is for a 
19MSWLF unit required to issue public notice under subsection 
20(p) of Section 39. The 90-day and 180-day time periods for the 
21Agency to take final action do not apply to NPDES permit 
22applications under subsection (b) of this Section, to RCRA 
23permit applications under subsection (d) of this Section, to 
24UIC permit applications under subsection (e) of this Section, 
25or to CCR surface impoundment applications under subsection 
26(y) of this Section.
 
 
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1    The Agency shall publish notice of all final permit 
2determinations for development permits for MSWLF units and for 
3significant permit modifications for lateral expansions for 
4existing MSWLF units one time in a newspaper of general 
5circulation in the county in which the unit is or is proposed 
6to be located.
7    After January 1, 1994 and until July 1, 1998, operating 
8permits issued under this Section by the Agency for sources of 
9air pollution permitted to emit less than 25 tons per year of 
10any combination of regulated air pollutants, as defined in 
11Section 39.5 of this Act, shall be required to be renewed only 
12upon written request by the Agency consistent with applicable 
13provisions of this Act and regulations promulgated hereunder. 
14Such operating permits shall expire 180 days after the date of 
15such a request. The Board shall revise its regulations for the 
16existing State air pollution operating permit program 
17consistent with this provision by January 1, 1994.
18    After June 30, 1998, operating permits issued under this 
19Section by the Agency for sources of air pollution that are not 
20subject to Section 39.5 of this Act and are not required to 
21have a federally enforceable State operating permit shall be 
22required to be renewed only upon written request by the Agency 
23consistent with applicable provisions of this Act and its 
24rules. Such operating permits shall expire 180 days after the 
25date of such a request. Before July 1, 1998, the Board shall 
26revise its rules for the existing State air pollution 
 
 
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1operating permit program consistent with this paragraph and 
2shall adopt rules that require a source to demonstrate that it 
3qualifies for a permit under this paragraph.
4    Each air pollution construction permit for fossil 
5fuel-fired power backup generators to a source that is a data 
6center, as defined in subsection (c) of Section 605-1025 of 
7the Department of Commerce and Economic Opportunity Law of the 
8Civil Administrative Code of Illinois, that is applied for 6 
9months after the effective date of this amendatory Act of the 
10104th General Assembly and that is required to have a 
11federally enforceable State operating permit or a Clean Air 
12Act Permit Program permit shall, in addition to any other 
13applicable requirements, require each generator to: (i) meet 
14standards at least as protective as Tier 4 standards for 
15non-road diesel engines set out by the United States 
16Environmental Protection Agency in 40 CFR 1039, as it exists 
17on the effective date of this amendatory Act of the 104th 
18General Assembly; and (ii) operate solely as an emergency or 
19standby unit in accordance with 35 Ill. Adm. Code 211.1920, as 
20it exists on the effective date of this amendatory Act of the 
21104th General Assembly.    
22    (b) The Agency may issue NPDES permits exclusively under 
23this subsection for the discharge of contaminants from point 
24sources into navigable waters, all as defined in the Federal 
25Water Pollution Control Act, as now or hereafter amended, 
26within the jurisdiction of the State, or into any well.
 
 
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1    All NPDES permits shall contain those terms and 
2conditions, including, but not limited to, schedules of 
3compliance, which may be required to accomplish the purposes 
4and provisions of this Act.
5    The Agency may issue general NPDES permits for discharges 
6from categories of point sources which are subject to the same 
7permit limitations and conditions. Such general permits may be 
8issued without individual applications and shall conform to 
9regulations promulgated under Section 402 of the Federal Water 
10Pollution Control Act, as now or hereafter amended.
11    The Agency may include, among such conditions, effluent 
12limitations and other requirements established under this Act, 
13Board regulations, the Federal Water Pollution Control Act, as 
14now or hereafter amended, and regulations pursuant thereto, 
15and schedules for achieving compliance therewith at the 
16earliest reasonable date.
17    The Agency shall adopt filing requirements and procedures 
18which are necessary and appropriate for the issuance of NPDES 
19permits, and which are consistent with the Act or regulations 
20adopted by the Board, and with the Federal Water Pollution 
21Control Act, as now or hereafter amended, and regulations 
22pursuant thereto.
23    The Agency, subject to any conditions which may be 
24prescribed by Board regulations, may issue NPDES permits to 
25allow discharges beyond deadlines established by this Act or 
26by regulations of the Board without the requirement of a 
 
 
10400SB0025ham002- 793 -LRB104 07069 AAS 28576 a

1variance, subject to the Federal Water Pollution Control Act, 
2as now or hereafter amended, and regulations pursuant thereto.
3    (c) Except for those facilities owned or operated by 
4sanitary districts organized under the Metropolitan Water 
5Reclamation District Act, no permit for the development or 
6construction of a new pollution control facility may be 
7granted by the Agency unless the applicant submits proof to 
8the Agency that the location of the facility has been approved 
9by the county board of the county if in an unincorporated area, 
10or the governing body of the municipality when in an 
11incorporated area, in which the facility is to be located in 
12accordance with Section 39.2 of this Act. For purposes of this 
13subsection (c), and for purposes of Section 39.2 of this Act, 
14the appropriate county board or governing body of the 
15municipality shall be the county board of the county or the 
16governing body of the municipality in which the facility is to 
17be located as of the date when the application for siting 
18approval is filed. 
19    In the event that siting approval granted pursuant to 
20Section 39.2 has been transferred to a subsequent owner or 
21operator, that subsequent owner or operator may apply to the 
22Agency for, and the Agency may grant, a development or 
23construction permit for the facility for which local siting 
24approval was granted. Upon application to the Agency for a 
25development or construction permit by that subsequent owner or 
26operator, the permit applicant shall cause written notice of 
 
 
10400SB0025ham002- 794 -LRB104 07069 AAS 28576 a

1the permit application to be served upon the appropriate 
2county board or governing body of the municipality that 
3granted siting approval for that facility and upon any party 
4to the siting proceeding pursuant to which siting approval was 
5granted. In that event, the Agency shall conduct an evaluation 
6of the subsequent owner or operator's prior experience in 
7waste management operations in the manner conducted under 
8subsection (i) of Section 39 of this Act.
9    Beginning August 20, 1993, if the pollution control 
10facility consists of a hazardous or solid waste disposal 
11facility for which the proposed site is located in an 
12unincorporated area of a county with a population of less than 
13100,000 and includes all or a portion of a parcel of land that 
14was, on April 1, 1993, adjacent to a municipality having a 
15population of less than 5,000, then the local siting review 
16required under this subsection (c) in conjunction with any 
17permit applied for after that date shall be performed by the 
18governing body of that adjacent municipality rather than the 
19county board of the county in which the proposed site is 
20located; and for the purposes of that local siting review, any 
21references in this Act to the county board shall be deemed to 
22mean the governing body of that adjacent municipality; 
23provided, however, that the provisions of this paragraph shall 
24not apply to any proposed site which was, on April 1, 1993, 
25owned in whole or in part by another municipality.
26    In the case of a pollution control facility for which a 
 
 
10400SB0025ham002- 795 -LRB104 07069 AAS 28576 a

1development permit was issued before November 12, 1981, if an 
2operating permit has not been issued by the Agency prior to 
3August 31, 1989 for any portion of the facility, then the 
4Agency may not issue or renew any development permit nor issue 
5an original operating permit for any portion of such facility 
6unless the applicant has submitted proof to the Agency that 
7the location of the facility has been approved by the 
8appropriate county board or municipal governing body pursuant 
9to Section 39.2 of this Act.
10    After January 1, 1994, if a solid waste disposal facility, 
11any portion for which an operating permit has been issued by 
12the Agency, has not accepted waste disposal for 5 or more 
13consecutive calendar years, before that facility may accept 
14any new or additional waste for disposal, the owner and 
15operator must obtain a new operating permit under this Act for 
16that facility unless the owner and operator have applied to 
17the Agency for a permit authorizing the temporary suspension 
18of waste acceptance. The Agency may not issue a new operation 
19permit under this Act for the facility unless the applicant 
20has submitted proof to the Agency that the location of the 
21facility has been approved or re-approved by the appropriate 
22county board or municipal governing body under Section 39.2 of 
23this Act after the facility ceased accepting waste.
24    Except for those facilities owned or operated by sanitary 
25districts organized under the Metropolitan Water Reclamation 
26District Act, and except for new pollution control facilities 
 
 
10400SB0025ham002- 796 -LRB104 07069 AAS 28576 a

1governed by Section 39.2, and except for fossil fuel mining 
2facilities, the granting of a permit under this Act shall not 
3relieve the applicant from meeting and securing all necessary 
4zoning approvals from the unit of government having zoning 
5jurisdiction over the proposed facility.
6    Before beginning construction on any new sewage treatment 
7plant or sludge drying site to be owned or operated by a 
8sanitary district organized under the Metropolitan Water 
9Reclamation District Act for which a new permit (rather than 
10the renewal or amendment of an existing permit) is required, 
11such sanitary district shall hold a public hearing within the 
12municipality within which the proposed facility is to be 
13located, or within the nearest community if the proposed 
14facility is to be located within an unincorporated area, at 
15which information concerning the proposed facility shall be 
16made available to the public, and members of the public shall 
17be given the opportunity to express their views concerning the 
18proposed facility.
19    The Agency may issue a permit for a municipal waste 
20transfer station without requiring approval pursuant to 
21Section 39.2 provided that the following demonstration is 
22made:
23        (1) the municipal waste transfer station was in 
24    existence on or before January 1, 1979 and was in 
25    continuous operation from January 1, 1979 to January 1, 
26    1993;
 
 
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1        (2) the operator submitted a permit application to the 
2    Agency to develop and operate the municipal waste transfer 
3    station during April of 1994;
4        (3) the operator can demonstrate that the county board 
5    of the county, if the municipal waste transfer station is 
6    in an unincorporated area, or the governing body of the 
7    municipality, if the station is in an incorporated area, 
8    does not object to resumption of the operation of the 
9    station; and
10        (4) the site has local zoning approval.
11    (d) The Agency may issue RCRA permits exclusively under 
12this subsection to persons owning or operating a facility for 
13the treatment, storage, or disposal of hazardous waste as 
14defined under this Act. Subsection (y) of this Section, rather 
15than this subsection (d), shall apply to permits issued for 
16CCR surface impoundments. 
17    All RCRA permits shall contain those terms and conditions, 
18including, but not limited to, schedules of compliance, which 
19may be required to accomplish the purposes and provisions of 
20this Act. The Agency may include among such conditions 
21standards and other requirements established under this Act, 
22Board regulations, the Resource Conservation and Recovery Act 
23of 1976 (P.L. 94-580), as amended, and regulations pursuant 
24thereto, and may include schedules for achieving compliance 
25therewith as soon as possible. The Agency shall require that a 
26performance bond or other security be provided as a condition 
 
 
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1for the issuance of a RCRA permit.
2    In the case of a permit to operate a hazardous waste or PCB 
3incinerator as defined in subsection (k) of Section 44, the 
4Agency shall require, as a condition of the permit, that the 
5operator of the facility perform such analyses of the waste to 
6be incinerated as may be necessary and appropriate to ensure 
7the safe operation of the incinerator.
8    The Agency shall adopt filing requirements and procedures 
9which are necessary and appropriate for the issuance of RCRA 
10permits, and which are consistent with the Act or regulations 
11adopted by the Board, and with the Resource Conservation and 
12Recovery Act of 1976 (P.L. 94-580), as amended, and 
13regulations pursuant thereto.
14    The applicant shall make available to the public for 
15inspection all documents submitted by the applicant to the 
16Agency in furtherance of an application, with the exception of 
17trade secrets, at the office of the county board or governing 
18body of the municipality. Such documents may be copied upon 
19payment of the actual cost of reproduction during regular 
20business hours of the local office. The Agency shall issue a 
21written statement concurrent with its grant or denial of the 
22permit explaining the basis for its decision.
23    (e) The Agency may issue UIC permits exclusively under 
24this subsection to persons owning or operating a facility for 
25the underground injection of contaminants as defined under 
26this Act.
 
 
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1    All UIC permits shall contain those terms and conditions, 
2including, but not limited to, schedules of compliance, which 
3may be required to accomplish the purposes and provisions of 
4this Act. The Agency may include among such conditions 
5standards and other requirements established under this Act, 
6Board regulations, the Safe Drinking Water Act (P.L. 93-523), 
7as amended, and regulations pursuant thereto, and may include 
8schedules for achieving compliance therewith. The Agency shall 
9require that a performance bond or other security be provided 
10as a condition for the issuance of a UIC permit.
11    The Agency shall adopt filing requirements and procedures 
12which are necessary and appropriate for the issuance of UIC 
13permits, and which are consistent with the Act or regulations 
14adopted by the Board, and with the Safe Drinking Water Act 
15(P.L. 93-523), as amended, and regulations pursuant thereto.
16    The applicant shall make available to the public for 
17inspection all documents submitted by the applicant to the 
18Agency in furtherance of an application, with the exception of 
19trade secrets, at the office of the county board or governing 
20body of the municipality. Such documents may be copied upon 
21payment of the actual cost of reproduction during regular 
22business hours of the local office. The Agency shall issue a 
23written statement concurrent with its grant or denial of the 
24permit explaining the basis for its decision.
25    (f) In making any determination pursuant to Section 9.1 of 
26this Act:
 
 
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1        (1) The Agency shall have authority to make the 
2    determination of any question required to be determined by 
3    the Clean Air Act, as now or hereafter amended, this Act, 
4    or the regulations of the Board, including the 
5    determination of the Lowest Achievable Emission Rate, 
6    Maximum Achievable Control Technology, or Best Available 
7    Control Technology, consistent with the Board's 
8    regulations, if any.
9        (2) The Agency shall adopt requirements as necessary 
10    to implement public participation procedures, including, 
11    but not limited to, public notice, comment, and an 
12    opportunity for hearing, which must accompany the 
13    processing of applications for PSD permits. The Agency 
14    shall briefly describe and respond to all significant 
15    comments on the draft permit raised during the public 
16    comment period or during any hearing. The Agency may group 
17    related comments together and provide one unified response 
18    for each issue raised.
19        (3) Any complete permit application submitted to the 
20    Agency under this subsection for a PSD permit shall be 
21    granted or denied by the Agency not later than one year 
22    after the filing of such completed application. 
23        (4) The Agency shall, after conferring with the 
24    applicant, give written notice to the applicant of its 
25    proposed decision on the application, including the terms 
26    and conditions of the permit to be issued and the facts, 
 
 
10400SB0025ham002- 801 -LRB104 07069 AAS 28576 a

1    conduct, or other basis upon which the Agency will rely to 
2    support its proposed action.
3    (g) The Agency shall include as conditions upon all 
4permits issued for hazardous waste disposal sites such 
5restrictions upon the future use of such sites as are 
6reasonably necessary to protect public health and the 
7environment, including permanent prohibition of the use of 
8such sites for purposes which may create an unreasonable risk 
9of injury to human health or to the environment. After 
10administrative and judicial challenges to such restrictions 
11have been exhausted, the Agency shall file such restrictions 
12of record in the Office of the Recorder of the county in which 
13the hazardous waste disposal site is located.
14    (h) A hazardous waste stream may not be deposited in a 
15permitted hazardous waste site unless specific authorization 
16is obtained from the Agency by the generator and disposal site 
17owner and operator for the deposit of that specific hazardous 
18waste stream. The Agency may grant specific authorization for 
19disposal of hazardous waste streams only after the generator 
20has reasonably demonstrated that, considering technological 
21feasibility and economic reasonableness, the hazardous waste 
22cannot be reasonably recycled for reuse, nor incinerated or 
23chemically, physically, or biologically treated so as to 
24neutralize the hazardous waste and render it nonhazardous. In 
25granting authorization under this Section, the Agency may 
26impose such conditions as may be necessary to accomplish the 
 
 
10400SB0025ham002- 802 -LRB104 07069 AAS 28576 a

1purposes of the Act and are consistent with this Act and 
2regulations promulgated by the Board hereunder. If the Agency 
3refuses to grant authorization under this Section, the 
4applicant may appeal as if the Agency refused to grant a 
5permit, pursuant to the provisions of subsection (a) of 
6Section 40 of this Act. For purposes of this subsection (h), 
7the term "generator" has the meaning given in Section 3.205 of 
8this Act, unless: (1) the hazardous waste is treated, 
9incinerated, or partially recycled for reuse prior to 
10disposal, in which case the last person who treats, 
11incinerates, or partially recycles the hazardous waste prior 
12to disposal is the generator; or (2) the hazardous waste is 
13from a response action, in which case the person performing 
14the response action is the generator. This subsection (h) does 
15not apply to any hazardous waste that is restricted from land 
16disposal under 35 Ill. Adm. Code 728.
17    (i) Before issuing any RCRA permit, any permit for a waste 
18storage site, sanitary landfill, waste disposal site, waste 
19transfer station, waste treatment facility, waste incinerator, 
20or any waste-transportation operation, any permit or interim 
21authorization for a clean construction or demolition debris 
22fill operation, or any permit required under subsection (d-5) 
23of Section 55, the Agency shall conduct an evaluation of the 
24prospective owner's or operator's prior experience in waste 
25management operations, clean construction or demolition debris 
26fill operations, and tire storage site management. The Agency 
 
 
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1may deny such a permit, or deny or revoke interim 
2authorization, if the prospective owner or operator or any 
3employee or officer of the prospective owner or operator has a 
4history of:
5        (1) repeated violations of federal, State, or local 
6    laws, regulations, standards, or ordinances in the 
7    operation of waste management facilities or sites, clean 
8    construction or demolition debris fill operation 
9    facilities or sites, or tire storage sites; or
10        (2) conviction in this or another State of any crime 
11    which is a felony under the laws of this State, or 
12    conviction of a felony in a federal court; or conviction 
13    in this or another state or federal court of any of the 
14    following crimes: forgery, official misconduct, bribery, 
15    perjury, or knowingly submitting false information under 
16    any environmental law, regulation, or permit term or 
17    condition; or
18        (3) proof of gross carelessness or incompetence in 
19    handling, storing, processing, transporting, or disposing 
20    of waste, clean construction or demolition debris, or used 
21    or waste tires, or proof of gross carelessness or 
22    incompetence in using clean construction or demolition 
23    debris as fill.
24    (i-5) Before issuing any permit or approving any interim 
25authorization for a clean construction or demolition debris 
26fill operation in which any ownership interest is transferred 
 
 
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1between January 1, 2005, and the effective date of the 
2prohibition set forth in Section 22.52 of this Act, the Agency 
3shall conduct an evaluation of the operation if any previous 
4activities at the site or facility may have caused or allowed 
5contamination of the site. It shall be the responsibility of 
6the owner or operator seeking the permit or interim 
7authorization to provide to the Agency all of the information 
8necessary for the Agency to conduct its evaluation. The Agency 
9may deny a permit or interim authorization if previous 
10activities at the site may have caused or allowed 
11contamination at the site, unless such contamination is 
12authorized under any permit issued by the Agency. 
13    (j) The issuance under this Act of a permit to engage in 
14the surface mining of any resources other than fossil fuels 
15shall not relieve the permittee from its duty to comply with 
16any applicable local law regulating the commencement, 
17location, or operation of surface mining facilities.
18    (k) A development permit issued under subsection (a) of 
19Section 39 for any facility or site which is required to have a 
20permit under subsection (d) of Section 21 shall expire at the 
21end of 2 calendar years from the date upon which it was issued, 
22unless within that period the applicant has taken action to 
23develop the facility or the site. In the event that review of 
24the conditions of the development permit is sought pursuant to 
25Section 40 or 41, or permittee is prevented from commencing 
26development of the facility or site by any other litigation 
 
 
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1beyond the permittee's control, such two-year period shall be 
2deemed to begin on the date upon which such review process or 
3litigation is concluded.
4    (l) No permit shall be issued by the Agency under this Act 
5for construction or operation of any facility or site located 
6within the boundaries of any setback zone established pursuant 
7to this Act, where such construction or operation is 
8prohibited.
9    (m) The Agency may issue permits to persons owning or 
10operating a facility for composting landscape waste. In 
11granting such permits, the Agency may impose such conditions 
12as may be necessary to accomplish the purposes of this Act, and 
13as are not inconsistent with applicable regulations 
14promulgated by the Board. Except as otherwise provided in this 
15Act, a bond or other security shall not be required as a 
16condition for the issuance of a permit. If the Agency denies 
17any permit pursuant to this subsection, the Agency shall 
18transmit to the applicant within the time limitations of this 
19subsection specific, detailed statements as to the reasons the 
20permit application was denied. Such statements shall include 
21but not be limited to the following:
22        (1) the Sections of this Act that may be violated if 
23    the permit were granted;
24        (2) the specific regulations promulgated pursuant to 
25    this Act that may be violated if the permit were granted;
26        (3) the specific information, if any, the Agency deems 
 
 
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1    the applicant did not provide in its application to the 
2    Agency; and
3        (4) a statement of specific reasons why the Act and 
4    the regulations might be violated if the permit were 
5    granted.
6    If no final action is taken by the Agency within 90 days 
7after the filing of the application for permit, the applicant 
8may deem the permit issued. Any applicant for a permit may 
9waive the 90-day limitation by filing a written statement with 
10the Agency.
11    The Agency shall issue permits for such facilities upon 
12receipt of an application that includes a legal description of 
13the site, a topographic map of the site drawn to the scale of 
14200 feet to the inch or larger, a description of the operation, 
15including the area served, an estimate of the volume of 
16materials to be processed, and documentation that:
17        (1) the facility includes a setback of at least 200 
18    feet from the nearest potable water supply well;
19        (2) the facility is located outside the boundary of 
20    the 10-year floodplain or the site will be floodproofed;
21        (3) the facility is located so as to minimize 
22    incompatibility with the character of the surrounding 
23    area, including at least a 200 foot setback from any 
24    residence, and in the case of a facility that is developed 
25    or the permitted composting area of which is expanded 
26    after November 17, 1991, the composting area is located at 
 
 
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1    least 1/8 mile from the nearest residence (other than a 
2    residence located on the same property as the facility);
3        (4) the design of the facility will prevent any 
4    compost material from being placed within 5 feet of the 
5    water table, will adequately control runoff from the site, 
6    and will collect and manage any leachate that is generated 
7    on the site;
8        (5) the operation of the facility will include 
9    appropriate dust and odor control measures, limitations on 
10    operating hours, appropriate noise control measures for 
11    shredding, chipping and similar equipment, management 
12    procedures for composting, containment and disposal of 
13    non-compostable wastes, procedures to be used for 
14    terminating operations at the site, and recordkeeping 
15    sufficient to document the amount of materials received, 
16    composted, and otherwise disposed of; and
17        (6) the operation will be conducted in accordance with 
18    any applicable rules adopted by the Board.
19    The Agency shall issue renewable permits of not longer 
20than 10 years in duration for the composting of landscape 
21wastes, as defined in Section 3.155 of this Act, based on the 
22above requirements.
23    The operator of any facility permitted under this 
24subsection (m) must submit a written annual statement to the 
25Agency on or before April 1 of each year that includes an 
26estimate of the amount of material, in tons, received for 
 
 
10400SB0025ham002- 808 -LRB104 07069 AAS 28576 a

1composting.
2    (n) The Agency shall issue permits jointly with the 
3Department of Transportation for the dredging or deposit of 
4material in Lake Michigan in accordance with Section 18 of the 
5Rivers, Lakes, and Streams Act.
6    (o) (Blank).
7    (p) (1) Any person submitting an application for a permit 
8for a new MSWLF unit or for a lateral expansion under 
9subsection (t) of Section 21 of this Act for an existing MSWLF 
10unit that has not received and is not subject to local siting 
11approval under Section 39.2 of this Act shall publish notice 
12of the application in a newspaper of general circulation in 
13the county in which the MSWLF unit is or is proposed to be 
14located. The notice must be published at least 15 days before 
15submission of the permit application to the Agency. The notice 
16shall state the name and address of the applicant, the 
17location of the MSWLF unit or proposed MSWLF unit, the nature 
18and size of the MSWLF unit or proposed MSWLF unit, the nature 
19of the activity proposed, the probable life of the proposed 
20activity, the date the permit application will be submitted, 
21and a statement that persons may file written comments with 
22the Agency concerning the permit application within 30 days 
23after the filing of the permit application unless the time 
24period to submit comments is extended by the Agency.
25    When a permit applicant submits information to the Agency 
26to supplement a permit application being reviewed by the 
 
 
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1Agency, the applicant shall not be required to reissue the 
2notice under this subsection.
3    (2) The Agency shall accept written comments concerning 
4the permit application that are postmarked no later than 30 
5days after the filing of the permit application, unless the 
6time period to accept comments is extended by the Agency.
7    (3) Each applicant for a permit described in part (1) of 
8this subsection shall file a copy of the permit application 
9with the county board or governing body of the municipality in 
10which the MSWLF unit is or is proposed to be located at the 
11same time the application is submitted to the Agency. The 
12permit application filed with the county board or governing 
13body of the municipality shall include all documents submitted 
14to or to be submitted to the Agency, except trade secrets as 
15determined under Section 7.1 of this Act. The permit 
16application and other documents on file with the county board 
17or governing body of the municipality shall be made available 
18for public inspection during regular business hours at the 
19office of the county board or the governing body of the 
20municipality and may be copied upon payment of the actual cost 
21of reproduction.
22    (q) Within 6 months after July 12, 2011 (the effective 
23date of Public Act 97-95), the Agency, in consultation with 
24the regulated community, shall develop a web portal to be 
25posted on its website for the purpose of enhancing review and 
26promoting timely issuance of permits required by this Act. At 
 
 
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1a minimum, the Agency shall make the following information 
2available on the web portal:
3        (1) Checklists and guidance relating to the completion 
4    of permit applications, developed pursuant to subsection 
5    (s) of this Section, which may include, but are not 
6    limited to, existing instructions for completing the 
7    applications and examples of complete applications. As the 
8    Agency develops new checklists and develops guidance, it 
9    shall supplement the web portal with those materials.
10        (2) Within 2 years after July 12, 2011 (the effective 
11    date of Public Act 97-95), permit application forms or 
12    portions of permit applications that can be completed and 
13    saved electronically, and submitted to the Agency 
14    electronically with digital signatures.
15        (3) Within 2 years after July 12, 2011 (the effective 
16    date of Public Act 97-95), an online tracking system where 
17    an applicant may review the status of its pending 
18    application, including the name and contact information of 
19    the permit analyst assigned to the application. Until the 
20    online tracking system has been developed, the Agency 
21    shall post on its website semi-annual permitting 
22    efficiency tracking reports that include statistics on the 
23    timeframes for Agency action on the following types of 
24    permits received after July 12, 2011 (the effective date 
25    of Public Act 97-95): air construction permits, new NPDES 
26    permits and associated water construction permits, and 
 
 
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1    modifications of major NPDES permits and associated water 
2    construction permits. The reports must be posted by 
3    February 1 and August 1 each year and shall include:
4            (A) the number of applications received for each 
5        type of permit, the number of applications on which 
6        the Agency has taken action, and the number of 
7        applications still pending; and
8            (B) for those applications where the Agency has 
9        not taken action in accordance with the timeframes set 
10        forth in this Act, the date the application was 
11        received and the reasons for any delays, which may 
12        include, but shall not be limited to, (i) the 
13        application being inadequate or incomplete, (ii) 
14        scientific or technical disagreements with the 
15        applicant, USEPA, or other local, state, or federal 
16        agencies involved in the permitting approval process, 
17        (iii) public opposition to the permit, or (iv) Agency 
18        staffing shortages. To the extent practicable, the 
19        tracking report shall provide approximate dates when 
20        cause for delay was identified by the Agency, when the 
21        Agency informed the applicant of the problem leading 
22        to the delay, and when the applicant remedied the 
23        reason for the delay.
24    (r) Upon the request of the applicant, the Agency shall 
25notify the applicant of the permit analyst assigned to the 
26application upon its receipt.
 
 
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1    (s) The Agency is authorized to prepare and distribute 
2guidance documents relating to its administration of this 
3Section and procedural rules implementing this Section. 
4Guidance documents prepared under this subsection shall not be 
5considered rules and shall not be subject to the Illinois 
6Administrative Procedure Act. Such guidance shall not be 
7binding on any party.
8    (t) Except as otherwise prohibited by federal law or 
9regulation, any person submitting an application for a permit 
10may include with the application suggested permit language for 
11Agency consideration. The Agency is not obligated to use the 
12suggested language or any portion thereof in its permitting 
13decision. If requested by the permit applicant, the Agency 
14shall meet with the applicant to discuss the suggested 
15language.
16    (u) If requested by the permit applicant, the Agency shall 
17provide the permit applicant with a copy of the draft permit 
18prior to any public review period.
19    (v) If requested by the permit applicant, the Agency shall 
20provide the permit applicant with a copy of the final permit 
21prior to its issuance. 
22    (w) An air pollution permit shall not be required due to 
23emissions of greenhouse gases, as specified by Section 9.15 of 
24this Act.
25    (x) If, before the expiration of a State operating permit 
26that is issued pursuant to subsection (a) of this Section and 
 
 
10400SB0025ham002- 813 -LRB104 07069 AAS 28576 a

1contains federally enforceable conditions limiting the 
2potential to emit of the source to a level below the major 
3source threshold for that source so as to exclude the source 
4from the Clean Air Act Permit Program, the Agency receives a 
5complete application for the renewal of that permit, then all 
6of the terms and conditions of the permit shall remain in 
7effect until final administrative action has been taken on the 
8application for the renewal of the permit. 
9    (y) The Agency may issue permits exclusively under this 
10subsection to persons owning or operating a CCR surface 
11impoundment subject to Section 22.59.
12    (z) If a mass animal mortality event is declared by the 
13Department of Agriculture in accordance with the Animal 
14Mortality Act:
15        (1) the owner or operator responsible for the disposal 
16    of dead animals is exempted from the following:
17            (i) obtaining a permit for the construction, 
18        installation, or operation of any type of facility or 
19        equipment issued in accordance with subsection (a) of 
20        this Section;
21            (ii) obtaining a permit for open burning in 
22        accordance with the rules adopted by the Board; and
23            (iii) registering the disposal of dead animals as 
24        an eligible small source with the Agency in accordance 
25        with Section 9.14 of this Act; 
26        (2) as applicable, the owner or operator responsible 
 
 
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1    for the disposal of dead animals is required to obtain the 
2    following permits:
3            (i) an NPDES permit in accordance with subsection 
4        (b) of this Section;
5            (ii) a PSD permit or an NA NSR permit in accordance 
6        with Section 9.1 of this Act;
7            (iii) a lifetime State operating permit or a 
8        federally enforceable State operating permit, in 
9        accordance with subsection (a) of this Section; or
10            (iv) a CAAPP permit, in accordance with Section 
11        39.5 of this Act. 
12    All CCR surface impoundment permits shall contain those 
13terms and conditions, including, but not limited to, schedules 
14of compliance, which may be required to accomplish the 
15purposes and provisions of this Act, Board regulations, the 
16Illinois Groundwater Protection Act and regulations pursuant 
17thereto, and the Resource Conservation and Recovery Act and 
18regulations pursuant thereto, and may include schedules for 
19achieving compliance therewith as soon as possible.
20    The Board shall adopt filing requirements and procedures 
21that are necessary and appropriate for the issuance of CCR 
22surface impoundment permits and that are consistent with this 
23Act or regulations adopted by the Board, and with the RCRA, as 
24amended, and regulations pursuant thereto.
25    The applicant shall make available to the public for 
26inspection all documents submitted by the applicant to the 
 
 
10400SB0025ham002- 815 -LRB104 07069 AAS 28576 a

1Agency in furtherance of an application, with the exception of 
2trade secrets, on its public internet website as well as at the 
3office of the county board or governing body of the 
4municipality where CCR from the CCR surface impoundment will 
5be permanently disposed. Such documents may be copied upon 
6payment of the actual cost of reproduction during regular 
7business hours of the local office.
8    The Agency shall issue a written statement concurrent with 
9its grant or denial of the permit explaining the basis for its 
10decision.
11(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22; 
12102-558, eff. 8-20-21; 102-813, eff. 5-13-22.)
 
13    Section 90-50. The Electric Vehicle Rebate Act is amended 
14by changing Sections 35, 40, and 45 as follows:
 
15    (415 ILCS 120/35)
16    Sec. 35. User fees. 
17    (a) The Office of the Secretary of State shall collect 
18annual user fees from any individual, partnership, 
19association, corporation, or agency of the United States 
20government that registers any combination of 10 or more of the 
21following types of motor vehicles in the Covered Area: (1) 
22vehicles of the First Division, as defined in the Illinois 
23Vehicle Code; (2) vehicles of the Second Division registered 
24under the B, C, D, F, H, MD, MF, MG, MH and MJ plate 
 
 
10400SB0025ham002- 816 -LRB104 07069 AAS 28576 a

1categories, as defined in the Illinois Vehicle Code; and (3) 
2commuter vans and livery vehicles as defined in the Illinois 
3Vehicle Code. This Section does not apply to vehicles 
4registered under the International Registration Plan under 
5Section 3-402.1 of the Illinois Vehicle Code. The user fee 
6shall be $20 for each vehicle registered in the Covered Area 
7for each fiscal year. The Office of the Secretary of State 
8shall collect the $20 when a vehicle's registration fee is 
9paid.
10    (b) Owners of State, county, and local government 
11vehicles, rental vehicles, antique vehicles, expanded-use 
12antique vehicles, electric vehicles, and motorcycles are 
13exempt from paying the user fees on such vehicles.
14    (c) The Office of the Secretary of State shall deposit the 
15user fees collected into the Electric Vehicle and Charging    
16Rebate Fund.
17(Source: P.A. 101-505, eff. 1-1-20; 102-662, eff. 9-15-21.)
 
18    (415 ILCS 120/40)
19    Sec. 40. Appropriations from the Electric Vehicle and 
20Charging Rebate Fund.     
21    (a) The Agency shall estimate the amount of user fees 
22expected to be collected under Section 35 of this Act for each 
23fiscal year. User fee funds shall be deposited into and 
24distributed from the Electric Vehicle and Charging Rebate Fund 
25in the following manner:    
 
 
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1        (1) Through fiscal year 2023, an annual amount not to 
2    exceed $225,000 may be appropriated to the Agency from the 
3    Electric Vehicle and Charging Rebate Fund to pay its costs 
4    of administering the programs authorized by Section 27 of 
5    this Act. Beginning in fiscal year 2024 and in each fiscal 
6    year thereafter, an annual amount not to exceed $600,000 
7    may be appropriated to the Agency from the Electric 
8    Vehicle and Charging Rebate Fund to pay its costs of 
9    administering the programs authorized by Section 27 of 
10    this Act. An amount not to exceed $225,000 may be 
11    appropriated to the Secretary of State from the Electric 
12    Vehicle and Charging Rebate Fund to pay the Secretary of 
13    State's costs of administering the programs authorized 
14    under this Act.    
15        (2) In fiscal year 2022 and each fiscal year 
16    thereafter, after appropriation of the amounts authorized 
17    by item (1) of subsection (a) of this Section, the 
18    remaining moneys estimated to be collected during each 
19    fiscal year shall be appropriated.    
20        (3) (Blank).    
21        (4) Moneys appropriated to fund the programs 
22    authorized in Sections 25 and 30 shall be expended only 
23    after they have been collected and deposited into the 
24    Electric Vehicle and Charging Rebate Fund.
25    (b) Amounts appropriated to and deposited into the 
26Electric Vehicle and Charging Rebate Fund from the General 
 
 
10400SB0025ham002- 818 -LRB104 07069 AAS 28576 a

1Revenue Fund, or any other fund, shall be distributed from the 
2Electric Vehicle and Charging Rebate Fund to fund the program 
3authorized in Section 27.
4(Source: P.A. 103-8, eff. 6-7-23; 103-363, eff. 7-28-23; 
5103-605, eff. 7-1-24; 104-6, eff. 7-1-25.)
 
6    (415 ILCS 120/45)
7    Sec. 45. Electric Vehicle and Charging Rebate Fund; 
8creation; deposit of user fees. A separate fund in the State 
9treasury Treasury called the Electric Vehicle and Charging    
10Rebate Fund is created, into which shall be transferred the 
11user fees as provided in Section 35, funds as provided in 
12Section 605-1075 of the Department of Commerce and Economic 
13Opportunity Law of the Civil Administrative Code of Illinois,    
14and any other revenues, deposits, State appropriations, 
15contributions, grants, gifts, bequests, legacies of money and 
16securities, or transfers as provided by law from, without 
17limitation, governmental entities, private sources, 
18foundations, trade associations, industry organizations, and 
19not-for-profit organizations.
20(Source: P.A. 102-662, eff. 9-15-21.)
 
21
ARTICLE 99.

 
22    Section 99-97. Severability. The provisions of this Act 
23are severable under Section 1.31 of the Statute on Statutes.".