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1		AN ACT concerning regulation.
2		Be it enacted by the People of the State of Illinois,
3		represented in the General Assembly:
4		ARTICLE 1.
5		Section 1-1. Short title. This Article may be cited as the
6		Municipal and Cooperative Electric Utility Transparent
7		Planning Act. References in this Article to "this Act" mean
8		this Article.
9		Section 1-5. Legislative findings and objectives. The
10		General 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.
16		Electric cooperatives are not-for-profit, member-owned
17		entities governed and managed by elected boards of
18		directors chosen by their member consumers. Due to their
19		governance structures, municipal and cooperative electric
20		utilities are exempt from certain regulatory requirements
21		under State and federal law.
22		(3) Because democratic elections by member-ratepayers

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1		or customers are the ultimate guarantor of the integrity
2		and cost-effectiveness of these utilities' operations,
3		access to information and decision-making is crucial to
4		ensuring management of these utilities is prudent and
5		responsive.
6		(4) While not always applicable to municipal and
7		electric cooperatives, integrated resource planning
8		processes have been used in other states to attempt to
9		avoid capacity shortfalls, minimize ratepayer costs, and
10		increase public participation in and knowledge of electric
11		generation portfolio choices.
12		(5) It is in the long-term best interests of State
13		electricity customers and member-ratepayers that
14		electricity is provided by a diverse portfolio of
15		generation resources that may include generation
16		ownership, power supply contracts, storage resources, and
17		demand-side programs that minimizes costs and strives to
18		ensure reliable service to customers while considering
19		environmental impacts and that long-term utility planning
20		can help facilitate the achievement of reasonable and
21		stable rates, reliability, and State and federal
22		environmental law through such portfolios.
23		(6) Municipal and electric cooperatives utilities
24		should perform a comprehensive analysis of their existing
25		portfolio and identify opportunities to minimize
26		member-ratepayer and customer costs while maintaining

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1		reliability and meeting State and federal environmental
2		law.
3		(7) To ensure utilities minimize ratepayer costs while
4		maintaining reliability and meeting State and federal
5		environmental law, and to increase transparency and
6		democratic participation, it is important that municipal
7		and cooperative electric utilities participate in an
8		integrated resource planning process with meaningful and
9		appropriate participation and engagement.
10		Section 1-10. Definitions. As used in this Act:
11		"Agency" means the Illinois Power Agency.
12		"Demand-side program" means a program implemented by or on
13		behalf of a utility to reduce retail customer consumption
14		(MWh) or shift the time of consumption of energy (MW) from end
15		users, including energy efficiency programs, demand-response
16		programs, and programs for the promotion or aggregation of
17		distributed generation.
18		"Electric cooperative" has the meaning given to that term
19		in Section 3-119 of the Public Utilities Act.
20		"Generation resource" means a facility for the generation
21		of electricity.
22		"Integrated resource plan" or "IRP" means the planning
23		process for a municipal power agency, municipality, or
24		electric cooperative to evaluate energy supply and demand in
25		order to meet long-term energy needs while minimizing costs

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1		and complying with federal and State environmental
2		requirements, consistent with this Act.
3		"Municipality" has the meaning given to that term in
4		Section 11-119.1-3 of the Illinois Municipal Code.
5		"Municipal power agency" has the meaning given to that
6		term in Section 11-119.1-3 of the Illinois Municipal Code
7		excluding single project municipal power agencies that do not
8		plan for the full requirements of their members.
9		"Renewable generation resource" means a resource for
10		generating electricity that uses wind, solar, hydro, or
11		geothermal energy.
12		"Storage resource" means a commercially available
13		technology that uses mechanical, chemical, or thermal
14		processes to store energy and deliver the stored energy as
15		electricity for use at a later time and is capable of being
16		controlled by the distribution or transmission entity managing
17		it, to enable and optimize the safe and reliable operation of
18		the electric system.
19		"Utility" means a municipal power agency, municipality, or
20		electric cooperative, including a generation and transmission
21		electric cooperative that provides wholesale electricity to
22		one or more distribution electric cooperatives.
23		Section 1-15. Purpose and contents of integrated resource
24		plan.
25		(a) Beginning on or before January 1, 2027, and every 5

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1		years thereafter on or before January 1, all generation and
2		transmission electric cooperatives with members in this State,
3		all municipal power agencies, and all municipalities and
4		distribution electric cooperatives that provide electricity
5		for service to more than 7,000 retail electric customer meters
6		shall initiate an integrated resource planning process to
7		prepare and issue a preliminary integrated resource plan to be
8		posted on its website by January 1 of the following year.
9		Municipalities and electric cooperatives that are members of,
10		and have a full requirements contract with, a municipal power
11		agency or generation and transmission electric cooperative may
12		adopt the integrated resource plan of such other utility. In
13		the alternative, a municipality or electric cooperative that
14		is a member of, and has other than a full requirements contract
15		with, a municipal power agency or generation and transmission
16		electric cooperative may include the resources or resource
17		planning of the municipal power agency or generation and
18		transmission electric cooperative in its integrated resource
19		plan, and the municipal power agency or generation and
20		transmission electric cooperative may adopt such
21		municipality's or electric cooperative's integrated resource
22		plan. An integrated resource plan completed by a utility on or
23		after January 1, 2024 shall satisfy the first integrated
24		resource plan requirement if it meets the criteria set forth
25		in subsections (b) through (d).
26		(b) The purposes of the integrated resource plan are to

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1		consider and evaluate the utility's current portfolio,
2		including electrical generation, power supply contracts,
3		storage, and demand-side programs; to forecast future load
4		changes; to facilitate prudent planning with respect to
5		reliability, resources, energy and capacity procurements,
6		power supply contract expiration, and timing of generation
7		retirement; to determine what resource portfolio will maintain
8		reliability consistent with RTO obligations; to minimize cost
9		and meet State and federal environmental law; and to
10		articulate steps the utility will take to minimize customer
11		costs and consider environmental impacts through changes to
12		its current generation portfolio through construction,
13		procurement, retirement, demand-side programs, or other
14		applicable technology or processes.
15		(c) As part of the integrated resource plan development
16		process, a utility shall consider all resources reasonably
17		available or reasonably likely to be available during the
18		relevant time period to satisfy the demand for electricity
19		services for a planning period of at least 5 years, taking into
20		account both supply-side and demand-side electric power
21		resources and cost and benefits projections for at least the
22		next 20 years.
23		(d) A utility may include the results of an all-source
24		request for proposals for generation resources and capacity
25		contracts for delivery beginning within the next 5 years in
26		its integrated resource plan. If the utility chooses not to

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1		include such results, the utility must provide notice to the
2		utility's ratepayers upon issuance of the integrated resource
3		plan that states why the utility has chosen not to include the
4		results. A utility also shall include the following, at a
5		minimum, in its integrated resource plan:
6		(1) A list of all electricity generation facilities
7		owned by the utility, in whole or in part. For each such
8		facility, the integrated resource plan shall report:
9		(A) general location;
10		(B) ownership information, if ownership is shared
11		with another entity;
12		(C) type of fuel;
13		(D) the date of commercial operation;
14		(E) expected useful life;
15		(F) expected retirement date for any resource
16		expected to retire within the next 8 years, and an
17		explanation of the reason for the retirement;
18		(G) nameplate, maximum output, and accredited
19		capacity;
20		(H) total MWh generated at the facility during the
21		previous calendar year;
22		(I) the date on which the facility is anticipated
23		to be fully depreciated; and
24		(J) any known and measurable compliance
25		obligations, or compliance obligations reasonably
26		expected to apply within the next 8 years, and an

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1		estimate of reasonably anticipated expenditures
2		intended to meet those obligations.
3		(2) A list of all power purchase agreements to which
4		the utility is a party, whether as purchaser or seller,
5		including the following, if specified: the counterparty,
6		general location and type of generation resource providing
7		power per the agreement, date on which the agreement was
8		entered into, duration of the agreement, and the energy
9		and capacity terms of the agreement.
10		(3) A list of any sale transactions of any capacity to
11		any purchaser.
12		(4) A list of any demand-side programs and known
13		distributed generation.
14		(5) A narrative description of all existing
15		transmission facilities owned by the utility, in whole or
16		in part, that identifies anticipated transmission
17		constraints or critical contingencies, and identification
18		of the regional transmission organization, if any, that
19		exercises operational control over the transmission
20		facility.
21		(6) A description of all transmission investment
22		costs, disaggregated by expenditure, related to
23		interconnection costs and other transmission system
24		upgrades associated with a new generating resource or
25		increased injection rights from an existing generating
26		resource costing greater than $1,000,000 over the term of

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1		the agreement.
2		(7) A copy of the most recent FERC Form 1 filed by the
3		utility. If no such FERC Form 1 has been filed, the utility
4		shall provide Form EIA 860, Form EIA 861, Form EIA 412, or
5		information applicable to the utility included in the
6		sections of FERC Form 1 or Form EIA 412 relating to
7		electric operating revenues, sales for resale, electric
8		operating and maintenance expenses, purchased power,
9		common utility plant and expenses, and electric energy
10		accounts for the prior calendar year. The utility shall
11		not be required to disclose any information required to be
12		protected from disclosure by the regional transmission
13		organizations.
14		(8) A range of load forecasts for the 5-year planning
15		period that incorporate varying assumptions regarding
16		electrification, economic growth, new regulation, and
17		major new customers, sufficient for capacity planning for
18		the utility. Such forecasts shall include:
19		(A) all relevant underlying assumptions;
20		(B) (i) historical analysis of hourly loads
21		consistent with NERC and regional transmission
22		organization reporting requirements; (ii) known or
23		projected changes to future loads; and (iii) growth
24		forecasts and trends by customer class or load type;
25		(C) analysis of the annual capacity and energy
26		impact of any demand-side programs, and energy

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1		efficiency programs both current and projected;
2		(D) any reserve margin or other obligations placed
3		on the utility by regional transmission organizations
4		or other entity responsible for reliability standards
5		under State or federal law; and
6		(E) a comparison of past load forecasts and actual
7		realized load and a brief narrative description of any
8		unforeseen events to which any discrepancy may be
9		attributed.
10		(9) A 5-year action plan for meeting the forecasted
11		load that reasonably minimizes customer cost taking into
12		account load, fuel price, and regulatory uncertainty, that
13		ensures reliability consistent with RTO obligations, and
14		meets State and federal environmental law. As part of the
15		action plan, the utility shall:
16		(A) Identify any generation or storage resources
17		reasonably anticipated to be removed from service in
18		the 5 years following the date on which the integrated
19		resource plan is due to be completed.
20		(B) Determine whether given forecasted load growth
21		or unit retirements, or both, the utility will need to
22		procure additional accredited capacity and energy, and
23		provide a quantitative estimate of any such gap
24		between forecasted load and supply-side resources.
25		(C) Provide a narrative description of the
26		utility's process for evaluating possible resources to

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1		secure additional needed capacity and energy.
2		(D) Provide a narrative description of the
3		utility's processes for assessing the economic value
4		of existing generation; and consistent with these
5		processes, explain whether any currently operating
6		units could be replaced by other resources at lower
7		cost to ratepayers while maintaining reliability.
8		(E) Identify a preferred portfolio of generation
9		resources, which may include storage, and demand-side
10		programs that, in the utility's judgment, meets its
11		forecasted load and complies with State and federal
12		environmental law, while minimizing ratepayer cost to
13		the extent reasonably achievable in the planning
14		period covered by the action plan. The portfolio shall
15		incorporate any accredited capacity or other
16		reliability requirements of any regional transmission
17		organization of which the utility is a member.
18		(F) Describe any anticipated capital expenditures
19		by the utility in excess of $1,000,000 at existing
20		generation facilities and the reason for such
21		expenditures.
22		(10) A description of all models and methodologies
23		used in performing the integrated resource planning
24		process. The utility shall provide, to any member of a
25		joint action agency or member of a generation and
26		transmission electric cooperative, reasonable access to

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1		computer models used in the analysis that are not
2		proprietary to the owner of the model, such as software
3		that cannot be used without a licensing agreement, or
4		otherwise subject to confidentiality by the modeler.
5		(e) As part of the initial integrated resource plan, the
6		utility shall identify all programs, grants, loans, or tax
7		benefits for which the utility has applied for or plans to
8		apply for pursuant to the federal Inflation Reduction Act of
9		2022 and shall state whether the utility has applied for or
10		otherwise used the program, grant, loan, or tax benefit.
11		(f) Each utility shall consider and include, as part of
12		its integrated resource plan, technically feasible least-cost
13		portfolio scenarios, consistent with RTO reliability
14		obligations, for constructing or procuring renewable energy
15		resources to meet 40% of its energy needs by 2030, meeting the
16		emissions reductions requirements under Public Act 102-662,
17		and supplying 100% of its total projected load through
18		carbon-free resources in combination with storage resources
19		and demand-side programs by 2045.
20		Section 1-20. Stakeholder process for municipal power
21		agencies and municipalities. Prior to the issuance of a final
22		integrated resource plan, a municipal power agency or
23		municipality required to prepare and issue an integrated
24		resource plan shall hold one or more stakeholder meetings open
25		to the municipal power agency's or municipality's ratepayers

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1		and members of the public before it issues a preliminary
2		integrated resource plan and one or more such stakeholder
3		meetings after the preliminary integrated resource plan is
4		issued.
5		Notice of the meetings shall be posted to the municipal
6		power agency's or municipality's website and notice of the
7		initial meeting to customers through the normal billing
8		process not less than 30 days prior to the initial meeting, and
9		any municipality planning to adopt a municipal power agency's
10		final integrated resource plan shall post the notice to its
11		website or a link to the notice on the municipality's website
12		and provide notice of the municipal power agency's initial
13		meeting to customers through the normal billing process not
14		less than 30 days prior to the initial meeting. During the
15		first meeting the municipal power agency or municipality shall
16		describe its proposed processes for developing the integrated
17		resource plan and its core assumptions and constraints. In
18		subsequent meetings, either before or after the preliminary
19		integrated resource plan is issued, the municipal power agency
20		or municipality shall present its proposed preferred
21		portfolio, and describe any planned retirements, capital
22		expenditures on existing generation resources likely to exceed
23		$1,000,000, and planned construction. Each meeting shall
24		provide opportunity for meaningful public engagement including
25		reasonable time to ask questions, have those questions
26		answered, and to provide public comment. Meetings shall be

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1		held at times accessible for working residents and shall be
2		recorded, and the municipal power agency or municipality may
3		consider language interpretation needs for non-English
4		speaking ratepayers in areas with a significant proportion of
5		non-English speaking residents. Following the meeting, the
6		municipal power agency or municipality shall provide attendees
7		with a reasonable means of providing public comment in writing
8		and of accessing the recording.
9		Section 1-25. Procedures for preliminary and final
10		integrated resource plans for municipal power agencies and
11		municipalities.
12		(a) Each municipal power agency or municipality shall
13		issue its preliminary integrated resource plan, as set forth
14		in this Act, and post it publicly to the website maintained by
15		the municipal power agency or municipality by January 1, 12
16		months following the date of the calendar year for which the
17		planning is required to begin. Any municipality planning to
18		adopt a municipal power agency's final integrated resource
19		plan shall post the preliminary integrated resource plan
20		publicly to its website or a link to it on the municipality's
21		website.
22		(b) The municipal power agency or municipality shall
23		facilitate public comment on the preliminary integrated
24		resource plan, as follows:
25		(1) upon issuance of the preliminary integrated

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1		resource plan, the municipal power agency or municipality
2		and any municipality planning to adopt a municipal power
3		agency's final integrated resource plan shall post the
4		preliminary integrated resource plan or a link to it
5		publicly on its website. The plan shall remain publicly
6		accessible for at least 60 days;
7		(2) the municipal power agency or municipality shall
8		hold one or more public meetings, in person with remote
9		access, where it shall make a representative available to
10		address questions about the preliminary integrated
11		resource plan. The meetings shall be held no sooner than
12		15 days, and no later than 45 days, after the preliminary
13		integrated resource plan is made available to the public;
14		(3) the municipal power agency or municipality shall
15		accept public comments on the preliminary integrated
16		resource plan for 30 days following its public posting via
17		website, email, or mail. The municipal power agency or
18		municipality may extend this public comment period by an
19		additional 30 days upon request by ratepayers of the
20		municipal power agency or municipality or any entity that
21		plans to adopt the municipal power agency's or
22		municipality's final integrated resource plan; and
23		(4) The municipal power agency or municipality shall
24		review public comments and provide responses that
25		reasonably address all relevant issues or questions raised
26		by such comments. The municipal power agency or

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1		municipality may modify its preliminary integrated
2		resource plan in response to these comments. The municipal
3		power agency or municipality shall prepare a document with
4		responses to public comments and submit this response
5		document to the Agency no later than 90 days after the
6		close of the comment period. This response document shall
7		be posted publicly on the municipality's or municipal
8		power agency's websites, as relevant, and on the website
9		of the Illinois Power Agency's website along with the
10		preliminary integrated resource plan, as submitted, and
11		any revisions made by the municipal power agency or
12		municipality in response to public comments.
13		(c) The Illinois Power Agency shall maintain public access
14		to all integrated resource plans submitted pursuant to this
15		Act, accessible through the Illinois Power Agency's website,
16		for no less than 10 years following each integrated resource
17		plan's initial submission.
18		Section 1-27. Member input and process for electric
19		cooperatives completing an integrated resource plan.
20		(a) Each electric cooperative completing an integrated
21		resource plan shall post its preliminary integrated resource
22		plan on its website no later than 60 days after completion of
23		the preliminary integrated resource plan. Any distribution
24		electric cooperative intending to adopt a generation and
25		transmission cooperative's integrated resource plan pursuant

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1		to Section 1-15 of this Act must also post the preliminary
2		integrated resource plan or a link to the preliminary
3		integrated resource plan on its own website. The preliminary
4		integrated resource plan must remain publicly accessible for
5		at least 60 days.
6		(b) After posting the preliminary integrated resource
7		plan, but before completion of a final integrated resource
8		plan, an electric cooperative preparing such a plan shall hold
9		at least one meeting open to its members, including members of
10		any member distribution cooperative and any other electric
11		cooperative adopting the integrated resource plan. An electric
12		cooperative intending to adopt the integrated resource plan
13		pursuant to Section 1-15 of this Act may, but is not required
14		to, hold its own meeting. If all other provisions of Section
15		1-15 are met, an electric cooperative may utilize its annual
16		meeting of members to comply with the meeting requirements set
17		forth in this Section.
18		(c) Notice of any meeting held pursuant to this Section
19		shall be posted on the website of any electric cooperative
20		whose members are eligible to attend the meeting and, if
21		applicable, provided to members through the electric
22		cooperative's normal billing process or regular communication
23		channel, at least 30 days prior to the meeting. An electric
24		cooperative intending to adopt the integrated resource plan
25		pursuant to Section 1-15 of this Act shall post the meeting
26		notice on its own website and notify members using the same

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1		timeline and methods.
2		(d) Each meeting shall provide an opportunity for
3		meaningful member participation, including sufficient time for
4		members to submit comments, ask questions, and receive
5		responses. Meetings shall be held at times convenient for
6		working members. The electric cooperative may consider
7		language interpretation needs for non-English speaking members
8		in areas with a significant non-English speaking population.
9		At a minimum, the electric cooperative shall present the
10		following information at the meeting:
11		(1) the purpose and process of developing an
12		integrated resource plan;
13		(2) the electric cooperative's process for developing
14		the integrated resource plan;
15		(3) the assumptions and scenarios considered by the
16		electric cooperative;
17		(4) an overview of supply and demand size resources
18		used to meet energy and capacity needs; and
19		(5) historical energy and capacity data, along with
20		assumptions regarding future load changes.
21		(e) Following the meeting, the electric cooperative shall
22		provide a reasonable opportunity for members to submit written
23		comments for at least 30 days. The electric cooperative shall
24		review written comments and prepare a response document that
25		summarizes and addresses relevant member comments. The
26		electric cooperative shall post the response document on its

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1		website within 90 days after the close of the comment period.
2		The electric cooperative may modify its preliminary integrated
3		resource plan in response to comments. If the electric
4		cooperative revises its preliminary integrated resource plan
5		in response to comments, it shall post the modified
6		preliminary integrated resource plan on its website.
7		(f) The Illinois Power Agency shall maintain a copy or a
8		link to an electric cooperative's integrated resource plan
9		completed pursuant to this Act on the Agency's website, for at
10		least 10 years from the date of each plan's initial
11		submission.
12		(g) An electric cooperative completing an integrated
13		resource plan may select their own consulting firm, complete
14		internally, or select a prequalified consulting firm from the
15		list maintained by the Agency.
16		Section 1-30. IRP prequalified consulting firm list.
17		(a) The Illinois Power Agency shall maintain a list of
18		qualified consulting firms for the purpose of developing
19		integrated resource plans on behalf of the utility. In order
20		to prequalify a consulting firm must have:
21		(1) direct previous experience preparing integrated
22		resource plans for utilities; assembling power supply
23		plans or portfolios for utilities;
24		(2) one or more employees with an advanced degree in
25		economics, mathematics, engineering, risk management, or a

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1		related area of study;
2		(3) 10 years of experience in the electricity sector;
3		(4) expertise in wholesale electricity market rules,
4		market planning, market development, and market modeling.
5		This includes, but is not limited to, expertise in current
6		and ongoing FERC Order implementation into RTO markets,
7		RTO governing documents, including, but not limited to,
8		transmission planning processes, and resource planning;
9		(5) expertise in wholesale electricity market rules,
10		including those established by the federal Energy
11		Regulatory Commission and regional transmission
12		organizations; and
13		(6) adequate resources to perform and fulfill the
14		required functions and responsibilities.
15		(b) No later than January 1, 2026 or the effective date of
16		this Act, whichever is later, the Illinois Power Agency shall
17		issue a Request for Information seeking responses from
18		consulting firms. Responses will be due within 45 days of that
19		issuance. The Agency will review responses and within 45 days
20		produce a list of prequalified consulting firms that the
21		Agency determines meet all of the prequalification
22		requirements contained in subsection (a) of this Section. A
23		firm determined not to meet the requirements may request to
24		submit additional information to the Agency for
25		reconsideration. If the Agency subsequently determines a firm
26		meets the requirements, the Agency shall add the firm to the

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1		list.
2		The list will be updated as additional consulting firms
3		request to be added to the list and the Agency determines they
4		meet the requirements contained in subsection (a) of this
5		Section 1-30. The Agency shall not arbitrarily or capriciously
6		deny inclusion to any qualified vendor that satisfies the
7		minimum qualifications set forth in this Section 1-30.
8		(c) The Illinois Power Agency shall publish the list of
9		prequalified consulting firms on its website. Upon request,
10		the Agency shall also provide each prequalified consulting
11		firm's response to the Request for Information to the affected
12		utility.
13		(d) A utility required to submit an integrated resource
14		plan may select a consulting firm on the Agency's list of
15		prequalified consulting firms to develop the integrated
16		resource plan and support stakeholder processes.
17		(e) The utility may apply for funding to offset its costs
18		for its integrated resource plan through the Small Utility
19		Clean Energy Planning Grant Program offered through the
20		Illinois Finance Authority in its role as Climate Bank for the
21		State of Illinois, subject to funding availability or subject
22		to appropriation, and in accordance with program requirements
23		and limitations.
24		Section 1-32. Planning purposes of an integrated resource
25		plan.

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1		(a) Nothing in this Act shall be construed to alter any
2		regulatory authority or jurisdiction of any State agency with
3		respect to any municipal power agency, municipality, or
4		cooperative.
5		(b) The submission, posting, or publication of an
6		integrated resource plan pursuant to this Act shall not create
7		any binding obligation, commitment, or duty upon the municipal
8		power agency, municipality, or electric cooperative regarding
9		the construction, retirement, or operation of any facility, or
10		the procurement of any resource.
11		(c) Nothing in this Act shall be construed to create a
12		private right of action to enforce its provisions.
13		Section 1-90. The Open Meetings Act is amended by changing
14		Section 2 as follows:
15		(5 ILCS 120/2)  (from Ch. 102, par. 42)
16		Sec. 2. Open meetings.
17		(a) Openness required. All meetings of public bodies shall
18		be open to the public unless excepted in subsection (c) and
19		closed in accordance with Section 2a.
20		(b) Construction of exceptions. The exceptions contained
21		in subsection (c) are in derogation of the requirement that
22		public bodies meet in the open, and therefore, the exceptions
23		are to be strictly construed, extending only to subjects
24		clearly within their scope. The exceptions authorize but do

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1		not require the holding of a closed meeting to discuss a
2		subject included within an enumerated exception.
3		(c) Exceptions. A public body may hold closed meetings to
4		consider the following subjects:
5		(1) The appointment, employment, compensation,
6		discipline, performance, or dismissal of specific
7		employees, specific individuals who serve as independent
8		contractors in a park, recreational, or educational
9		setting, or specific volunteers of the public body or
10		legal counsel for the public body, including hearing
11		testimony on a complaint lodged against an employee, a
12		specific individual who serves as an independent
13		contractor in a park, recreational, or educational
14		setting, or a volunteer of the public body or against
15		legal counsel for the public body to determine its
16		validity. However, a meeting to consider an increase in
17		compensation to a specific employee of a public body that
18		is subject to the Local Government Wage Increase
19		Transparency Act may not be closed and shall be open to the
20		public and posted and held in accordance with this Act.
21		(2) Collective negotiating matters between the public
22		body and its employees or their representatives, or
23		deliberations concerning salary schedules for one or more
24		classes of employees.
25		(3) The selection of a person to fill a public office,
26		as defined in this Act, including a vacancy in a public

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1		office, when the public body is given power to appoint
2		under law or ordinance, or the discipline, performance or
3		removal of the occupant of a public office, when the
4		public body is given power to remove the occupant under
5		law or ordinance.
6		(4) Evidence or testimony presented in open hearing,
7		or in closed hearing where specifically authorized by law,
8		to a quasi-adjudicative body, as defined in this Act,
9		provided that the body prepares and makes available for
10		public inspection a written decision setting forth its
11		determinative reasoning.
12		(4.5) Evidence or testimony presented to a school
13		board regarding denial of admission to school events or
14		property pursuant to Section 24-24 of the School Code,
15		provided that the school board prepares and makes
16		available for public inspection a written decision setting
17		forth its determinative reasoning.
18		(5) The purchase or lease of real property for the use
19		of the public body, including meetings held for the
20		purpose of discussing whether a particular parcel should
21		be acquired.
22		(6) The setting of a price for sale or lease of
23		property owned by the public body.
24		(7) The sale or purchase of securities, investments,
25		or investment contracts. This exception shall not apply to
26		the investment of assets or income of funds deposited into

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1		the Illinois Prepaid Tuition Trust Fund.
2		(8) Security procedures, school building safety and
3		security, and the use of personnel and equipment to
4		respond to an actual, a threatened, or a reasonably
5		potential danger to the safety of employees, students,
6		staff, the public, or public property.
7		(9) Student disciplinary cases.
8		(10) The placement of individual students in special
9		education programs and other matters relating to
10		individual students.
11		(11) Litigation, when an action against, affecting or
12		on behalf of the particular public body has been filed and
13		is pending before a court or administrative tribunal, or
14		when the public body finds that an action is probable or
15		imminent, in which case the basis for the finding shall be
16		recorded and entered into the minutes of the closed
17		meeting.
18		(12) The establishment of reserves or settlement of
19		claims as provided in the Local Governmental and
20		Governmental Employees Tort Immunity Act, if otherwise the
21		disposition of a claim or potential claim might be
22		prejudiced, or the review or discussion of claims, loss or
23		risk management information, records, data, advice or
24		communications from or with respect to any insurer of the
25		public body or any intergovernmental risk management
26		association or self insurance pool of which the public

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1		body is a member.
2		(13) Conciliation of complaints of discrimination in
3		the sale or rental of housing, when closed meetings are
4		authorized by the law or ordinance prescribing fair
5		housing practices and creating a commission or
6		administrative agency for their enforcement.
7		(14) Informant sources, the hiring or assignment of
8		undercover personnel or equipment, or ongoing, prior or
9		future criminal investigations, when discussed by a public
10		body with criminal investigatory responsibilities.
11		(15) Professional ethics or performance when
12		considered by an advisory body appointed to advise a
13		licensing or regulatory agency on matters germane to the
14		advisory body's field of competence.
15		(16) Self evaluation, practices and procedures or
16		professional ethics, when meeting with a representative of
17		a statewide association of which the public body is a
18		member.
19		(17) The recruitment, credentialing, discipline or
20		formal peer review of physicians or other health care
21		professionals, or for the discussion of matters protected
22		under the federal Patient Safety and Quality Improvement
23		Act of 2005, and the regulations promulgated thereunder,
24		including 42 C.F.R. Part 3 (73 FR 70732), or the federal
25		Health Insurance Portability and Accountability Act of
26		1996, and the regulations promulgated thereunder,

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1		including 45 C.F.R. Parts 160, 162, and 164, by a
2		hospital, or other institution providing medical care,
3		that is operated by the public body.
4		(18) Deliberations for decisions of the Prisoner
5		Review Board.
6		(19) Review or discussion of applications received
7		under the Experimental Organ Transplantation Procedures
8		Act.
9		(20) The classification and discussion of matters
10		classified as confidential or continued confidential by
11		the State Government Suggestion Award Board.
12		(21) Discussion of minutes of meetings lawfully closed
13		under this Act, whether for purposes of approval by the
14		body of the minutes or semi-annual review of the minutes
15		as mandated by Section 2.06.
16		(22) Deliberations for decisions of the State
17		Emergency Medical Services Disciplinary Review Board.
18		(23) The operation by a municipality of a municipal
19		utility or the operation of a municipal power agency or
20		municipal natural gas agency when the discussion involves:
21		(i) trade secrets or commercial or financial information
22		obtained from a person or business where the trade secrets
23		or commercial or financial information are furnished under
24		a claim that they are proprietary, privileged, or
25		confidential, and that disclosure of the trade secrets or
26		commercial or financial information would cause

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1		competitive harm to the person or business; or
2		commercially sensitive information contained in offers to
3		buy or sell made in the competitive markets of a regional
4		transmission organization; and only insofar as the
5		discussion relates directly to such trade secrets or
6		information; (ii) physical or cybersecurity of facilities
7		or materials designated as Critical Energy/Electric
8		Infrastructure Information under federal law or
9		regulation; or (iii) ongoing contract negotiations or
10		results of a request for proposals relating to the
11		purchase, sale, or delivery of electricity or natural gas
12		from nonaffiliate entities; provided however, the
13		municipality, municipal power agency, or municipal natural
14		gas agency shall hold at least one public meeting as to any
15		contract discussed in whole or in part in closed session
16		prior to final action on the contract. (i) contracts
17		relating to the purchase, sale, or delivery of electricity
18		or natural gas or (ii) the results or conclusions of load
19		forecast studies.
20		(24) Meetings of a residential health care facility
21		resident sexual assault and death review team or the
22		Executive Council under the Abuse Prevention Review Team
23		Act.
24		(25) Meetings of an independent team of experts under
25		Brian's Law.
26		(26) Meetings of a mortality review team appointed

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1		under the Department of Juvenile Justice Mortality Review
2		Team Act.
3		(27) (Blank).
4		(28) Correspondence and records (i) that may not be
5		disclosed under Section 11-9 of the Illinois Public Aid
6		Code or (ii) that pertain to appeals under Section 11-8 of
7		the Illinois Public Aid Code.
8		(29) Meetings between internal or external auditors
9		and governmental audit committees, finance committees, and
10		their equivalents, when the discussion involves internal
11		control weaknesses, identification of potential fraud risk
12		areas, known or suspected frauds, and fraud interviews
13		conducted in accordance with generally accepted auditing
14		standards of the United States of America.
15		(30) (Blank).
16		(31) Meetings and deliberations for decisions of the
17		Concealed Carry Licensing Review Board under the Firearm
18		Concealed Carry Act.
19		(32) Meetings between the Regional Transportation
20		Authority Board and its Service Boards when the discussion
21		involves review by the Regional Transportation Authority
22		Board of employment contracts under Section 28d of the
23		Metropolitan Transit Authority Act and Sections 3A.18 and
24		3B.26 of the Regional Transportation Authority Act.
25		(33) Those meetings or portions of meetings of the
26		advisory committee and peer review subcommittee created

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1		under Section 320 of the Illinois Controlled Substances
2		Act during which specific controlled substance prescriber,
3		dispenser, or patient information is discussed.
4		(34) Meetings of the Tax Increment Financing Reform
5		Task Force under Section 2505-800 of the Department of
6		Revenue Law of the Civil Administrative Code of Illinois.
7		(35) Meetings of the group established to discuss
8		Medicaid capitation rates under Section 5-30.8 of the
9		Illinois Public Aid Code.
10		(36) Those deliberations or portions of deliberations
11		for decisions of the Illinois Gaming Board in which there
12		is discussed any of the following: (i) personal,
13		commercial, financial, or other information obtained from
14		any source that is privileged, proprietary, confidential,
15		or a trade secret; or (ii) information specifically
16		exempted from the disclosure by federal or State law.
17		(37) Deliberations for decisions of the Illinois Law
18		Enforcement Training Standards Board, the Certification
19		Review Panel, and the Illinois State Police Merit Board
20		regarding certification and decertification.
21		(38) Meetings of the Ad Hoc Statewide Domestic
22		Violence Fatality Review Committee of the Illinois
23		Criminal Justice Information Authority Board that occur in
24		closed executive session under subsection (d) of Section
25		35 of the Domestic Violence Fatality Review Act.
26		(39) Meetings of the regional review teams under

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1		subsection (a) of Section 75 of the Domestic Violence
2		Fatality Review Act.
3		(40) Meetings of the Firearm Owner's Identification
4		Card Review Board under Section 10 of the Firearm Owners
5		Identification Card Act.
6		(d) Definitions. For purposes of this Section:
7		"Employee" means a person employed by a public body whose
8		relationship with the public body constitutes an
9		employer-employee relationship under the usual common law
10		rules, and who is not an independent contractor.
11		"Public office" means a position created by or under the
12		Constitution or laws of this State, the occupant of which is
13		charged with the exercise of some portion of the sovereign
14		power of this State. The term "public office" shall include
15		members of the public body, but it shall not include
16		organizational positions filled by members thereof, whether
17		established by law or by a public body itself, that exist to
18		assist the body in the conduct of its business.
19		"Quasi-adjudicative body" means an administrative body
20		charged by law or ordinance with the responsibility to conduct
21		hearings, receive evidence or testimony and make
22		determinations based thereon, but does not include local
23		electoral boards when such bodies are considering petition
24		challenges.
25		(e) Final action. No final action may be taken at a closed
26		meeting. Final action shall be preceded by a public recital of

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1		the nature of the matter being considered and other
2		information that will inform the public of the business being
3		conducted.
4		(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21;
5		102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff.
6		7-28-23; 103-626, eff. 1-1-25.)
7		Section 1-95. The Public Utilities Act is amended by
8		changing Section 8-406 as follows:
9		(220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
10		Sec. 8-406. Certificate of public convenience and
11		necessity.
12		(a) No public utility not owning any city or village
13		franchise nor engaged in performing any public service or in
14		furnishing any product or commodity within this State as of
15		July 1, 1921 and not possessing a certificate of public
16		convenience and necessity from the Illinois Commerce
17		Commission, the State Public Utilities Commission, or the
18		Public Utilities Commission, at the time Public Act 84-617
19		goes into effect (January 1, 1986), shall transact any
20		business in this State until it shall have obtained a
21		certificate from the Commission that public convenience and
22		necessity require the transaction of such business. A
23		certificate of public convenience and necessity requiring the
24		transaction of public utility business in any area of this

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1		State shall include authorization to the public utility
2		receiving the certificate of public convenience and necessity
3		to construct such plant, equipment, property, or facility as
4		is provided for under the terms and conditions of its tariff
5		and as is necessary to provide utility service and carry out
6		the transaction of public utility business by the public
7		utility in the designated area.
8		(b) No public utility shall begin the construction of any
9		new plant, equipment, property, or facility which is not in
10		substitution of any existing plant, equipment, property, or
11		facility, or any extension or alteration thereof or in
12		addition thereto, unless and until it shall have obtained from
13		the Commission a certificate that public convenience and
14		necessity require such construction. Whenever after a hearing
15		the Commission determines that any new construction or the
16		transaction of any business by a public utility will promote
17		the public convenience and is necessary thereto, it shall have
18		the power to issue certificates of public convenience and
19		necessity. The Commission shall determine that proposed
20		construction will promote the public convenience and necessity
21		only if the utility demonstrates: (1) that the proposed
22		construction is necessary to provide adequate, reliable, and
23		efficient service to its customers and is the least-cost means
24		of satisfying the service needs of its customers or that the
25		proposed construction will promote the development of an
26		effectively competitive electricity market that operates

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1		efficiently, is equitable to all customers, and is the
2		least-cost least cost means of satisfying those objectives;
3		(2) that the utility is capable of efficiently managing and
4		supervising the construction process and has taken sufficient
5		action to ensure adequate and efficient construction and
6		supervision thereof; and (3) that the utility is capable of
7		financing the proposed construction without significant
8		adverse financial consequences for the utility or its
9		customers.
10		(b-5) As used in this subsection (b-5):
11		"Qualifying direct current applicant" means an entity that
12		seeks to provide direct current bulk transmission service for
13		the purpose of transporting electric energy in interstate
14		commerce.
15		"Qualifying direct current project" means a high voltage
16		direct current electric service line that crosses at least one
17		Illinois border, the Illinois portion of which is physically
18		located within the region of the Midcontinent Independent
19		System Operator, Inc., or its successor organization, and runs
20		through the counties of Pike, Scott, Greene, Macoupin,
21		Montgomery, Christian, Shelby, Cumberland, and Clark, is
22		capable of transmitting electricity at voltages of 345
23		kilovolts or above, and may also include associated
24		interconnected alternating current interconnection facilities
25		in this State that are part of the proposed project and
26		reasonably necessary to connect the project with other

SB0025 Enrolled - 35 - LRB104 07069 BAB 17106 b
1		portions of the grid.
2		Notwithstanding any other provision of this Act, a
3		qualifying direct current applicant that does not own,
4		control, operate, or manage, within this State, any plant,
5		equipment, or property used or to be used for the transmission
6		of electricity at the time of its application or of the
7		Commission's order may file an application on or before
8		December 31, 2023 with the Commission pursuant to this Section
9		or Section 8-406.1 for, and the Commission may grant, a
10		certificate of public convenience and necessity to construct,
11		operate, and maintain a qualifying direct current project. The
12		qualifying direct current applicant may also include in the
13		application requests for authority under Section 8-503. The
14		Commission shall grant the application for a certificate of
15		public convenience and necessity and requests for authority
16		under Section 8-503 if it finds that the qualifying direct
17		current applicant and the proposed qualifying direct current
18		project satisfy the requirements of this subsection and
19		otherwise satisfy the criteria of this Section or Section
20		8-406.1 and the criteria of Section 8-503, as applicable to
21		the application and to the extent such criteria are not
22		superseded by the provisions of this subsection. The
23		Commission's order on the application for the certificate of
24		public convenience and necessity shall also include the
25		Commission's findings and determinations on the request or
26		requests for authority pursuant to Section 8-503. Prior to

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1		filing its application under either this Section or Section
2		8-406.1, the qualifying direct current applicant shall conduct
3		3 public meetings in accordance with subsection (h) of this
4		Section. If the qualifying direct current applicant
5		demonstrates in its application that the proposed qualifying
6		direct current project is designed to deliver electricity to a
7		point or points on the electric transmission grid in either or
8		both the PJM Interconnection, LLC or the Midcontinent
9		Independent System Operator, Inc., or their respective
10		successor organizations, the proposed qualifying direct
11		current project shall be deemed to be, and the Commission
12		shall find it to be, for public use. If the qualifying direct
13		current applicant further demonstrates in its application that
14		the proposed transmission project has a capacity of 1,000
15		megawatts or larger and a voltage level of 345 kilovolts or
16		greater, the proposed transmission project shall be deemed to
17		satisfy, and the Commission shall find that it satisfies, the
18		criteria stated in item (1) of subsection (b) of this Section
19		or in paragraph (1) of subsection (f) of Section 8-406.1, as
20		applicable to the application, without the taking of
21		additional evidence on these criteria. Prior to the transfer
22		of functional control of any transmission assets to a regional
23		transmission organization, a qualifying direct current
24		applicant shall request Commission approval to join a regional
25		transmission organization in an application filed pursuant to
26		this subsection (b-5) or separately pursuant to Section 7-102

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1		of this Act. The Commission may grant permission to a
2		qualifying direct current applicant to join a regional
3		transmission organization if it finds that the membership, and
4		associated transfer of functional control of transmission
5		assets, benefits Illinois customers in light of the attendant
6		costs and is otherwise in the public interest. Nothing in this
7		subsection (b-5) requires a qualifying direct current
8		applicant to join a regional transmission organization.
9		Nothing in this subsection (b-5) requires the owner or
10		operator of a high voltage direct current transmission line
11		that is not a qualifying direct current project to obtain a
12		certificate of public convenience and necessity to the extent
13		it is not otherwise required by this Section 8-406 or any other
14		provision of this Act.
15		(c) As used in this subsection (c):
16		"Decommissioning" has the meaning given to that term in
17		subsection (a) of Section 8-508.1.
18		"Nuclear power reactor" has the meaning given to that term
19		in Section 8 of the Nuclear Safety Law of 2004.
20		After the effective date of this amendatory Act of the
21		103rd General Assembly, no construction shall commence on any
22		new nuclear power reactor with a nameplate capacity of more
23		than 300 megawatts of electricity to be located within this
24		State, and no certificate of public convenience and necessity
25		or other authorization shall be issued therefor by the
26		Commission, until the Illinois Emergency Management Agency and

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1		Office of Homeland Security, in consultation with the Illinois
2		Environmental Protection Agency and the Illinois Department of
3		Natural Resources, finds that the United States Government,
4		through its authorized agency, has identified and approved a
5		demonstrable technology or means for the disposal of high
6		level nuclear waste, or until such construction has been
7		specifically approved by a statute enacted by the General
8		Assembly. Beginning January 1, 2026, construction may commence
9		on a new nuclear power reactor with a nameplate capacity of 300
10		megawatts of electricity or less within this State if the
11		entity constructing the new nuclear power reactor has obtained
12		all permits, licenses, permissions, or approvals governing the
13		construction, operation, and funding of decommissioning of
14		such nuclear power reactors required by: (1) this Act; (2) any
15		rules adopted by the Illinois Emergency Management Agency and
16		Office of Homeland Security under the authority of this Act;
17		(3) any applicable federal statutes, including, but not
18		limited to, the Atomic Energy Act of 1954, the Energy
19		Reorganization Act of 1974, the Low-Level Radioactive Waste
20		Policy Amendments Act of 1985, and the Energy Policy Act of
21		1992; (4) any regulations promulgated or enforced by the U.S.
22		Nuclear Regulatory Commission, including, but not limited to,
23		those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of
24		the Code of Federal Regulations, as from time to time amended;
25		and (5) any other federal or State statute, rule, or
26		regulation governing the permitting, licensing, operation, or

SB0025 Enrolled - 39 - LRB104 07069 BAB 17106 b
1		decommissioning of such nuclear power reactors. None of the
2		rules developed by the Illinois Emergency Management Agency
3		and Office of Homeland Security or any other State agency,
4		board, or commission pursuant to this Act shall be construed
5		to supersede the authority of the U.S. Nuclear Regulatory
6		Commission. The changes made by this amendatory Act of the
7		103rd General Assembly shall not apply to the uprate, renewal,
8		or subsequent renewal of any license for an existing nuclear
9		power reactor that began operation prior to the effective date
10		of this amendatory Act of the 103rd General Assembly.
11		None of the changes made in this amendatory Act of the
12		104th General Assembly this amendatory Act of the 103rd
13		General Assembly are intended to authorize the construction of
14		nuclear power plants powered by nuclear power reactors that
15		are not either: (1) small modular nuclear reactors; or (2)
16		nuclear power reactors licensed by the U.S. Nuclear Regulatory
17		Commission to operate in this State prior to the effective
18		date of this amendatory Act of the 103rd General Assembly.
19		(d) In making its determination under subsection (b) of
20		this Section, the Commission shall attach primary weight to
21		the cost or cost savings to the customers of the utility. The
22		Commission may consider any or all factors which will or may
23		affect such cost or cost savings, including the public
24		utility's engineering judgment regarding the materials used
25		for construction.
26		(e) The Commission may issue a temporary certificate which

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1		shall remain in force not to exceed one year in cases of
2		emergency, to assure maintenance of adequate service or to
3		serve particular customers, without notice or hearing, pending
4		the determination of an application for a certificate, and may
5		by regulation exempt from the requirements of this Section
6		temporary acts or operations for which the issuance of a
7		certificate will not be required in the public interest.
8		A public utility shall not be required to obtain but may
9		apply for and obtain a certificate of public convenience and
10		necessity pursuant to this Section with respect to any matter
11		as to which it has received the authorization or order of the
12		Commission under the Electric Supplier Act, and any such
13		authorization or order granted a public utility by the
14		Commission under that Act shall as between public utilities be
15		deemed to be, and shall have except as provided in that Act the
16		same force and effect as, a certificate of public convenience
17		and necessity issued pursuant to this Section.
18		No electric cooperative shall be made or shall become a
19		party to or shall be entitled to be heard or to otherwise
20		appear or participate in any proceeding initiated under this
21		Section for authorization of power plant construction and as
22		to matters as to which a remedy is available under the Electric
23		Supplier Act.
24		(f) Such certificates may be altered or modified by the
25		Commission, upon its own motion or upon application by the
26		person or corporation affected. Unless exercised within a

SB0025 Enrolled - 41 - LRB104 07069 BAB 17106 b
1		period of 2 years from the grant thereof, authority conferred
2		by a certificate of convenience and necessity issued by the
3		Commission shall be null and void.
4		No certificate of public convenience and necessity shall
5		be construed as granting a monopoly or an exclusive privilege,
6		immunity or franchise.
7		(g) A public utility that undertakes any of the actions
8		described in items (1) through (3) of this subsection (g) or
9		that has obtained approval pursuant to Section 8-406.1 of this
10		Act shall not be required to comply with the requirements of
11		this Section to the extent such requirements otherwise would
12		apply. For purposes of this Section and Section 8-406.1 of
13		this Act, "high voltage electric service line" means an
14		electric line having a design voltage of 69,000 100,000 or
15		more. For purposes of this subsection (g), a public utility
16		may do any of the following:
17		(1) replace or upgrade any existing high voltage
18		electric service line and related facilities,
19		notwithstanding its length or, subject to applicable
20		Article VII requirements, ownership;
21		(2) relocate any existing high voltage electric
22		service line and related facilities, notwithstanding its
23		length, to accommodate construction or expansion of a
24		roadway or other transportation infrastructure; or
25		(3) construct a high voltage electric service line and
26		related facilities that is constructed solely to serve a

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1		single customer's premises or to provide a generator
2		interconnection to the public utility's transmission
3		system and that will (i) pass under or over the premises
4		owned by the customer or generator to be served; (ii) pass
5		or under or over premises for which the customer or
6		generator has secured the necessary right of way
7		right-of-way; or (iii) be multi-circuited with the
8		facilities of the public utility.
9		(h) A public utility seeking to construct a high-voltage
10		electric service line and related facilities (Project) must
11		show that the utility has held a minimum of 2 pre-filing public
12		meetings to receive public comment concerning the Project in
13		each county where the Project is to be located, no earlier than
14		6 months prior to filing an application for a certificate of
15		public convenience and necessity from the Commission. Notice
16		of the public meeting shall be published in a newspaper of
17		general circulation within the affected county once a week for
18		3 consecutive weeks, beginning no earlier than one month prior
19		to the first public meeting. If the Project traverses 2
20		contiguous counties and where in one county the transmission
21		line mileage and number of landowners over whose property the
22		proposed route traverses is one-fifth or less of the
23		transmission line mileage and number of such landowners of the
24		other county, then the utility may combine the 2 pre-filing
25		meetings in the county with the greater transmission line
26		mileage and affected landowners. All other requirements

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1		regarding pre-filing meetings shall apply in both counties.
2		Notice of the public meeting, including a description of the
3		Project, must be provided in writing to the clerk of each
4		county where the Project is to be located. A representative of
5		the Commission shall be invited to each pre-filing public
6		meeting.
7		(h-5) A public utility seeking to construct a high-voltage
8		electric service line and related facilities must also show
9		that the Project has complied with training and competence
10		requirements under subsection (b) of Section 15 of the
11		Electric Transmission Systems Construction Standards Act.
12		(i) For applications filed after August 18, 2015 (the
13		effective date of Public Act 99-399), the Commission shall, by
14		certified mail, notify each owner of record of land, as
15		identified in the records of the relevant county tax assessor,
16		included in the right-of-way over which the utility seeks in
17		its application to construct a high-voltage electric line of
18		the time and place scheduled for the initial hearing on the
19		public utility's application. The utility shall reimburse the
20		Commission for the cost of the postage and supplies incurred
21		for mailing the notice.
22		(j) In determining whether to issue a certificate of
23		public convenience for a new electric generation facility to a
24		municipal power agency that is required to obtain such a
25		certificate to exercise its power of eminent domain pursuant
26		to Section 11-119.1-10 of the Illinois Municipal Code, the

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1		Commission shall give due consideration to whether a
2		generation unit of similar size and type is part of the
3		municipal power agency's preferred portfolio or least-cost
4		plan for achieving renewable energy goals in its most recent
5		integrated resource plan, as described in subsection (d) of
6		Section 1-15 of the Municipal and Cooperative Electric Utility
7		Transparent Planning Act.
8		(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21;
9		102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff.
10		6-1-24; 103-1066, eff. 2-20-25.)
11		Section 1-100. The General Not For Profit Corporation Act
12		of 1986 is amended by adding Section 108.22 as follows:
13		(805 ILCS 105/108.22 new)
14		Sec. 108.22. Distribution electric cooperatives.
15		(a) A distribution electric cooperative, as that term is
16		used in the Electric Supplier Act, shall maintain a publicly
17		accessible website and shall post the following documents and
18		information on its website:
19		(1) The current bylaws.
20		(2) A schedule of all regular meetings, posted
21		annually and updated as necessary.
22		(3) Planned agendas for all regular and special board
23		meetings.
24		(4) Minutes of the regular session of each board

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1		meeting, posted within 30 days of their approval.
2		(5) A description of the director election process,
3		including:
4		(A) eligibility requirements for director
5		candidates;
6		(B) nomination procedures;
7		(C) voting methods and member instructions; and
8		(D) election timelines and deadlines.
9		(b) A distribution electric cooperative may include in its
10		bylaws procedures for accepting votes cast by mail or through
11		secure online voting platforms.
12		(c) Each distribution electric cooperative shall adopt
13		bylaws or written policies establishing a process that allows
14		members to address the board of directors on matters relevant
15		to the governance and operation of the cooperative.
16		ARTICLE 5.
17		Section 5-1. Short title. This Article may be cited as the
18		Utility Data Access Act. References in this Article to "this
19		Act" mean this Article.
20		Section 5-5. Findings.
21		(a) The General Assembly finds and declares that
22		optimizing energy use through whole-building utility data
23		access is in the public interest because it provides

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1		consumers, building owners, utilities, and states with
2		significant economic benefits.
3		(b) The General Assembly further finds the following:
4		(1) implementing building energy use data access
5		legislation catalyzes the development of a strong market
6		for building energy services which will positively impact
7		the State's economy through significant job growth;
8		(2) improving the energy use efficiency of the
9		existing building stock is a key strategy to help preserve
10		the affordability of rental housing;
11		(3) energy use reductions stemming from data access
12		can result in direct cost savings to customers and in peak
13		load reductions that benefit all ratepayers;
14		(4) data access programs allow utilities to maximize
15		the value of their energy use efficiency portfolio by
16		engaging customers and directing them to energy efficiency
17		programs and by enabling utilities to target
18		low-performing buildings;
19		(5) implementing building data access enables building
20		owners in the State to qualify for certain federal and
21		other incentives to help them improve their assets;
22		(6) energy use data access is the foundation of a
23		successful efficiency strategy and enables building owners
24		to track energy use performance over time, set performance
25		goals, and justify cost-effective energy use upgrades; and
26		(7) absent whole-building energy use data access

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1		legislation, building owners lack an efficient, defined
2		process to obtain energy performance of their buildings in
3		a manner that protects consumer confidentiality.
4		Section 5-10. Definitions. As used in this Act:
5		"Account holder" or "customer" means the person or entity
6		authorized to access or modify utility account details.
7		"Aggregated usage data" means an aggregation of covered
8		usage data, where all data associated with a qualified
9		building or qualified property, including, but not limited to,
10		data from tenant meters and from owner meters, are combined
11		into one collective data point per utility data type, per time
12		period, and where any unique identifiers or other personal
13		information are removed or dissociated from individual meter
14		data.
15		"Aggregation threshold" means 3 or more unique
16		nonresidential qualified accounts or any combination of 5 or
17		more residential and nonresidential unique qualified accounts
18		of a property or building during the period for which data is
19		requested.
20		"Benchmarking tool" means the ENERGY STAR Portfolio
21		Manager web-based tool or any prudent and cost-effective
22		alternative system or tool approved by the Commission should
23		ENERGY STAR Portfolio Manager become inoperative or no longer
24		useful to achieving the policy goals of the State of Illinois
25		that (i) enables the periodic entry of a building's energy use

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1		data and other descriptive information about a building and
2		(ii) rates a building's energy efficiency against that of
3		comparable buildings nationwide.
4		"Commission" means the Illinois Commerce Commission.
5		"Covered usage data" means electric data collected from
6		one or more utility meters that reflects the quantity and
7		period of utility usage in the building, property, or portion
8		thereof.
9		"Data recipient" means:
10		(1) an owner of the property or building;
11		(2) an owner of a portion of a property with regard to
12		covered usage data only for the utility consumption the
13		owner or the owner's tenants, if any, pay for and consume
14		in the owned portion;
15		(3) a tenant with regard to covered usage data only
16		for the utility consumption the tenant or the tenant's
17		subtenants, if any, pay for and consume in the space
18		leased by the tenant;
19		(4) the board, in the case of a condominium or
20		cooperative ownership of the property or building; or
21		(5) an agent authorized to receive the covered usage
22		data by anyone in paragraphs (1) through (4).
23		"Property" means:
24		(1) a single tax parcel;
25		(2) 2 or more tax parcels held in the cooperative or
26		condominium form of ownership and governed by a single

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1		board of managers; or
2		(3) 2 or more colocated tax parcels owned or
3		controlled by the same entity.
4		"Qualified account" means a utility account that serves
5		some or all of a building or property for which covered usage
6		data is requested and that, as affirmed by the data recipient,
7		was not controlled by the data recipient or its subsidiary
8		during the time period for which covered usage data is
9		requested.
10		"Qualified building" means a building that meets the
11		aggregation threshold.
12		"Qualified data recipient" means a data recipient with
13		respect to a qualified property or qualified building.
14		"Qualified property" means a property that meets the
15		aggregation threshold.
16		"Utility" means an entity that is an electric utility with
17		over 500,000 customers in this State and that is a public
18		utility, as defined in Section 3-105 of the Public Utilities
19		Act.
20		"Utility data type" means electric.
21		Section 5-15. Utility data access.
22		(a) Within 90 days after the effective date of this Act,
23		the Commission shall open a proceeding to establish by rule,
24		consistent with the Illinois Administrative Procedure Act and
25		the requirements of subsection (c), procedures to implement

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1		the requirements of this Section. The Commission shall
2		consider industry best practices along with Illinois law,
3		rules, and Commission orders in developing the implementing
4		rules. The governing authority of a public utility district,
5		municipally owned utility, or cooperative utility may adopt a
6		rule adopted by the Commission.
7		(b) No later than 2 years after the effective date of this
8		Act, the Commission shall adopt procedures through the
9		rulemaking proceeding identified in subsection (a) whereby:
10		(1) a utility shall retain usage data in the
11		possession of the utility on the effective date of this
12		Act or that is subsequently generated by the utility, for
13		a period 5 years or however long the utility retains usage
14		data in its active billing system, whichever is longer;
15		(2) a utility shall honor an account holder's
16		authorized request to transmit the account holder's
17		covered usage data held by the utility to any entity
18		designated by the account holder;
19		(3) a qualified data recipient with respect to a
20		qualified building or qualified property may request that
21		a utility provide aggregated usage data for the qualified
22		building or qualified property. Aggregated usage data
23		shall include identifiers of all meters associated with
24		the aggregate data and any other information needed for
25		data quality assurance;
26		(4) a utility shall establish a tool or process to

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1		enable qualified data recipients to request data under
2		this subsection. The tool or process shall meet
3		specifications established by the Commission;
4		(5) the account holder request process and utility
5		delivery of requested data shall be convenient, secure,
6		and at the Commission's direction requests to the utility
7		may be submitted exclusively through an online portal; and
8		(6) a utility shall provide updates or corrections to
9		any previously provided usage information on the schedule
10		established in paragraph (5) of subsection (d). Data
11		recipients may request and receive timely revisions
12		correcting any previously provided usage information. A
13		utility shall also provide usage information on the
14		schedule established in paragraph (5) of subsection (d).
15		(c) Any covered usage data that a utility provides to a
16		data recipient under this Section must meet the following
17		requirements:
18		(1) The covered usage data must be available to be
19		requested online. A utility's validation of the
20		requester's identity shall be consistent with, and no more
21		onerous than, the utility's then-current practices.
22		(2) The covered usage data must be provided to the
23		data recipient in a timeframe, frequency, and format and
24		be delivered by a method as may be determined by the
25		Commission.
26		(d) Any covered usage data that a utility provides to a

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1		data recipient under this Section must:
2		(1) be provided to the data recipient within 30 days
3		after receiving the data recipient's valid request if the
4		request is received after the effective date of the
5		rulemaking identified in subsection (a) of this Section;
6		(2) for any initial upload of data to a data recipient
7		and subject to subsection (j) of this Section, a data
8		recipient must include all the data for the time period
9		required in paragraph (1) of subsection (b), regardless of
10		whether the data recipient had a business relationship
11		with the building or property during that period;
12		(3) include all necessary data and available usage
13		data points for data recipients to comply with reporting
14		requirements to which they are subject, including any such
15		usage data that the utility possesses;
16		(4) be directly uploaded to the benchmarking tool
17		account, or delivered in another format approved by the
18		Commission, depending on utility size under subsection
19		(e);
20		(5) be provided to the data recipient according to a
21		schedule set by the Commission, but no less than monthly;
22		(6) be provided until the data recipient revokes the
23		request for usage data or is no longer a data recipient or
24		is no longer a qualified data recipient with respect to
25		aggregated usage data;
26		(7) be accompanied by a list of all meters associated

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1		with the covered usage data, including, but not limited
2		to, aggregated usage data, and shall be accompanied by any
3		other information the Commission deems necessary including
4		for data quality assurance; and
5		(8) be provided at no cost to the data recipient.
6		(e) The Commission shall direct that covered usage data
7		shall be delivered to the data recipient in a standard format
8		consistent with the benchmarking tool at the data recipient's
9		request. The Commission shall direct electric utilities that
10		serve at least 500,000 customers in the State to provide
11		requested data by direct upload to the benchmarking tool and
12		associate the data with the data recipient's benchmarking tool
13		account.
14		(f) To ensure the validity and usefulness of covered usage
15		data, the utility shall provide the best available consumption
16		and other information, consistent with the utility's records
17		as presented to account holders on the utility's customer
18		portal and captured at the meter level.
19		(g) Once covered usage data has been made available to a
20		duly authorized data recipient, such data may not be deleted
21		or altered by a utility system, except as is necessary to
22		correct errors or reflect rebills or is affected as part of the
23		utility's billing data retention policy. If previously
24		provided covered usage data is changed to correct errors,
25		notification must be provided to the data recipient.
26		(h) Within 180 days after the effective date of this Act,

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1		the Commission shall adopt a standard form for a utility
2		account holder to authorize the sharing of the utility account
3		holder's covered usage data.
4		(i) For properties that do not meet the aggregation
5		threshold and therefore require account holder authorization,
6		the utility shall provide covered usage data to data
7		recipients upon account holder authorization, which:
8		(1) may be provided in Commission-approved form;
9		(2) may be provided in a lease agreement provision;
10		and
11		(3) remains valid until the account holder revokes it,
12		regardless of how the authorization is provided.
13		(j) Access to covered usage data under this Section shall
14		be subject to any rules the Commission has adopted or may
15		choose to adopt, if the rules do not conflict with this
16		Section.
17		(k) Except in cases where the utility has not followed
18		processes established by this Act or the utility is grossly
19		negligent, the utility shall be held harmless for third-party
20		misuse of data shared under this Act and no cause of action may
21		be initiated against the utility for such subsequent misuse.
22		(l) A utility may file for cost recovery of the reasonable
23		and prudently incurred costs of providing covered usage data,
24		including establishing, operating, and maintaining data
25		aggregation and data access services, for the Commission to
26		evaluate. A utility shall make good faith efforts to secure

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1		federal, State, or other relevant funding for such investments
2		in the future. Any such funding the utility receives shall be
3		deducted from future revenue requirements.
4		(m) The Commission may hire consultants and experts to
5		execute their responsibilities under this Act, with the
6		retention of those consultants and experts exempt from the
7		requirements of Section 20-10 of the Illinois Procurement
8		Code.
9		ARTICLE 90.
10		Section 90-5. The Department of Commerce and Economic
11		Opportunity Law of the Civil Administrative Code of Illinois
12		is amended by changing Section 605-1075 as follows:
13		(20 ILCS 605/605-1075)
14		Sec. 605-1075. Energy Transition Assistance Fund.
15		(a) The General Assembly hereby declares that management
16		of several economic development programs requires a
17		consolidated funding source to improve resource efficiency.
18		The General Assembly specifically recognizes that properly
19		serving communities and workers impacted by the energy
20		transition requires that the Department of Commerce and
21		Economic Opportunity have access to the resources required for
22		the execution of the programs for workforce and contractor
23		development, just transition investments and community

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1		support, and the implementation and administration of energy
2		and justice efforts by the State.
3		(b) The Department shall be responsible for the
4		administration of the Energy Transition Assistance Fund and
5		shall allocate funding on the basis of priorities established
6		in this Section. Each year, the Department shall determine the
7		available amount of resources in the Fund that can be
8		allocated to the programs identified in this Section, and
9		allocate the funding accordingly. The Department shall, to the
10		extent practical, consider both the short-term and long-term
11		costs of the programs and allocate funding so that the
12		Department is able to cover both the short-term and long-term
13		costs of these programs using projected revenue.
14		The available funding for each year shall be allocated
15		from the Fund in the following order of priority:
16		(1) for costs related to the Clean Jobs Workforce
17		Network Program, up to $21,000,000 annually prior to June
18		1, 2023; and $24,333,333 annually from June 1, 2023 to May
19		30, 2026; and $26,500,000 annually thereafter;
20		(2) for costs related to the Clean Energy Contractor
21		Incubator Program, up to $21,000,000 annually prior to
22		June 1, 2026 and up to $22,687,403 thereafter;
23		(3) for costs related to the Clean Energy Primes
24		Contractor Accelerator Program, up to $9,000,000 annually;
25		(4) for costs related to the Barrier Reduction
26		Program, up to $21,000,000 annually prior to June 1, 2026

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1		and up to $22,143,079 annually thereafter;
2		(5) for costs related to the Jobs and Environmental
3		Justice Grant Program, up to $34,000,000 annually prior to
4		June 1, 2026 and up to $41,000,000 annually thereafter;
5		(6) for costs related to the Returning Residents Clean
6		Jobs Training Program, up to $6,000,000 annually;
7		(7) for costs related to Energy Transition Navigators,
8		up to $6,000,000 annually prior to June 1, 2026 and up to
9		$6,500,000 annually thereafter;
10		(8) for costs related to the Illinois Climate Works
11		Preapprenticeship Program, up to $10,000,000 annually;
12		(9) for costs related to Energy Transition Community
13		Support Grants, up to $40,000,000 annually;
14		(10) for costs related to the Displaced Energy Worker
15		Dependent Scholarship, upon request by the Illinois
16		Student Assistance Commission, up to $1,100,000 annually;
17		(11) up to $10,000,000 annually shall be transferred
18		to the Public Utilities Fund for use by the Illinois
19		Commerce Commission for costs of administering the changes
20		made to the Public Utilities Act by this amendatory Act of
21		the 102nd General Assembly;
22		(12) up to $4,000,000 annually shall be transferred to
23		the Illinois Power Agency Operations Fund for use by the
24		Illinois Power Agency; and
25		(13) for costs related to the Clean Energy Jobs and
26		Justice Fund, up to $1,000,000 annually.

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1		The Department is authorized to utilize up to 10% of the
2		Energy Transition Assistance Fund for administrative and
3		operational expenses to implement the requirements of this
4		Act.
5		(b-5) Beginning January 1, 2028, at the direction of the
6		Department, the State Comptroller shall direct and the State
7		Treasurer shall transfer up to $84,800,000 annually into the
8		Electric Vehicle and Charging Fund from the Energy Transition
9		Assistance Fund for costs related to transportation
10		electrification programs, as described in Section 36 of the
11		Electric Vehicle Rebate Act. The Environmental Protection
12		Agency may use up to 3% of the annual allocation under this
13		subsection (b-5) for administrative and operational expenses.
14		(c) Within 30 days after the effective date of this
15		amendatory Act of the 102nd General Assembly, each electric
16		utility serving more than 500,000 customers in the State shall
17		report to the Department its total kilowatt-hours of energy
18		delivered during the 12 months ending on the immediately
19		preceding May 31. By October 31, 2021 and each October 31
20		thereafter, each electric utility serving more than 500,000
21		customers in the State shall report to the Department its
22		total kilowatt-hours of energy delivered during the 12 months
23		ending on the immediately preceding May 31.
24		(d) The Department shall, within 60 days after the
25		effective date of this amendatory Act of the 102nd General
26		Assembly:

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1		(1) determine the amount necessary, but not more than
2		$180,000,000, to meet the funding needs of the programs
3		reliant upon the Energy Transition Assistance Fund as a
4		revenue source for the period between the effective date
5		of this amendatory Act of the 102nd General Assembly and
6		December 31, 2021;
7		(2) determine, based on the kilowatt-hour deliveries
8		for the 12 months ending May 31, 2021 reported by the
9		electric utilities under subsection (c), the total energy
10		transition assistance charge to be allocated to each
11		electric utility for the period between the effective date
12		of this amendatory Act of the 102nd General Assembly and
13		December 31, 2021; and
14		(3) report the total energy transition assistance
15		charge applicable until December 31, 2021 to each electric
16		utility serving more than 500,000 customers in the State
17		and the Illinois Commerce Commission for purposes of
18		filing the tariff pursuant to Section 16-108.30 of the
19		Public Utilities Act.
20		(d-5) Notwithstanding subsection (d), the Department
21		shall, within 60 days after the effective date of this
22		amendatory Act of the 104th General Assembly, determine the
23		amount necessary, but not more than $192,000,000, to meet the
24		funding needs of the programs reliant upon the Energy
25		Transition Assistance Fund as a revenue source.
26		(e) The Department shall by November 30, 2021, and each

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1		November 30 thereafter:
2		(1) determine the amount necessary, but not more than
3		$180,000,000 before the effective date of this amendatory
4		Act of the 104th General Assembly and not more than
5		$192,000,000, plus the amount needed to fund the programs
6		described in subsection (b-5), after the effective date of
7		this amendatory Act of the 104th General Assembly, to meet
8		the funding needs of the programs reliant upon the Energy
9		Transition Assistance Fund as a revenue source for the
10		immediately 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		$192,000,000 plus the amount needed to fund the programs
25		described in subsection (b-5) $180,000,000 annually. If, at
26		the end of the calendar year, any surplus remains in the Energy

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1		Transition Assistance Fund, the Department may allocate the
2		surplus from the 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
18		changing Sections 45 and 55 as follows:
19		(20 ILCS 627/45)
20		Sec. 45. Beneficial electrification.
21		(a) It is the intent of the General Assembly to decrease
22		reliance on fossil fuels, reduce pollution from the
23		transportation sector, increase access to electrification for
24		all consumers, and ensure that electric vehicle adoption and

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1		increased electricity usage and demand do not place
2		significant additional burdens on the electric system and
3		create 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

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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
18		lower carbon dioxide emissions, replace fossil fuel use,
19		create cost savings, improve electric grid operations, reduce
20		increases to peak demand, improve electric usage load shape,
21		and align electric usage with times of renewable generation.
22		All beneficial electrification programs shall provide for
23		incentives such that customers are induced to use electricity
24		at times of low overall system usage or at times when
25		generation from renewable energy sources is high. "Beneficial
26		electrification programs" include a portfolio of the

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1		following:
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
15		people who are members of the groups described in
16		subparagraphs (a) through (e) of paragraph (A) of subsection
17		(1) of Section 2 of the Business Enterprise for Minorities,
18		Women, 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
22		powered by and refueled by electricity, must be plugged in to
23		charge, and is licensed to drive on public roadways. "Electric
24		vehicle" does not include electric mopeds, electric
25		off-highway vehicles, or hybrid electric vehicles and
26		extended-range electric vehicles that are also equipped with

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1		conventional fueled propulsion or auxiliary engines.
2		"Electric vehicle charging station" means a station that
3		delivers electricity from a source outside an electric vehicle
4		into one or more electric vehicles.
5		"Environmental justice communities" means the definition
6		of that term based on existing methodologies and findings,
7		used and as may be updated by the Illinois Power Agency and its
8		program administrator in the Illinois Solar for All Program.
9		"Equity investment eligible community" or "eligible
10		community" means the geographic areas throughout Illinois
11		which would most benefit from equitable investments by the
12		State designed to combat discrimination and foster sustainable
13		economic growth. Specifically, "eligible community" means the
14		following 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"
26		means the persons who would most benefit from equitable

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1		investments by the State designed to combat discrimination and
2		foster sustainable economic growth. Specifically, "eligible
3		person" 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
10		not exceed 80% of the state median income for the current State
11		fiscal year as established by the U.S. Department of Health
12		and Human Services.
13		"Make-ready infrastructure" means the electrical and
14		construction work necessary between the distribution circuit
15		to the connection point of charging equipment.
16		"Optimized charging programs" mean programs whereby owners
17		of electric vehicles can set their vehicles to be charged
18		based on the electric system's current demand, retail or
19		wholesale market rates, incentives, the carbon or other
20		pollution intensity of the electric generation mix, the
21		provision of grid services, efficient use of the electric
22		grid, or the availability of clean energy generation.
23		Optimized charging programs may be operated by utilities as
24		well as third parties.
25		(c) The Commission shall initiate a workshop process no
26		later than November 30, 2021 for the purpose of soliciting

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1		input on the design of beneficial electrification programs
2		that the utility shall offer. The workshop shall be
3		coordinated by the Staff of the Commission, or a facilitator
4		retained by Staff, and shall be organized and facilitated in a
5		manner that encourages representation from diverse
6		stakeholders, including stakeholders representing
7		environmental justice and low-income communities, and ensures
8		equitable opportunities for participation, without requiring
9		formal intervention or representation by an attorney.
10		The stakeholder workshop process shall take into
11		consideration the benefits of electric vehicle adoption and
12		barriers 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,
12		enabling rate structures, and other opportunities for the bill
13		reduction and environmental benefits described in this
14		subsection.
15		The workshop process shall conclude no later than February
16		28, 2022. Following the workshop, the Staff of the Commission,
17		or the facilitator retained by the Staff, shall prepare and
18		submit a report, no later than March 31, 2022, to the
19		Commission that includes, but is not limited to,
20		recommendations for transportation electrification investment
21		or 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
16		process, program designs proposed during the process,
17		estimates of the costs and benefits of proposed programs, any
18		material issues that remained unresolved at the conclusions of
19		such process, and any recommendations for workshop process
20		improvements. The report shall be used by the Commission to
21		inform and evaluate the cost-effectiveness cost effectiveness
22		and achievement of goals within the submitted Beneficial
23		Electrification Plans.
24		(d) No later than July 1, 2022, electric utilities serving
25		greater than 500,000 customers in the State shall file a
26		Beneficial Electrification Plan with the Illinois Commerce

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1		Commission for programs that start no later than January 1,
2		2023. The plan shall take into consideration recommendations
3		from the workshop report described in this Section. Within 45
4		days after the filing of the Beneficial Electrification Plan,
5		the Commission shall, with reasonable notice, open an
6		investigation to consider whether the plan meets the
7		objectives and contains the information required by this
8		Section. The Commission shall determine if the proposed plan
9		is cost-beneficial and in the public interest. When
10		considering if the plan is in the public interest and
11		determining appropriate levels of cost recovery for
12		investments and expenditures related to programs proposed by
13		an electric utility, the Commission shall consider whether the
14		investments and other expenditures are designed and reasonably
15		expected 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
5		total cost of beneficial electrification expenditures is less
6		than the net present value of increased electricity costs
7		(defined as marginal avoided energy, avoided capacity, and
8		avoided transmission and distribution system costs) avoided by
9		programs under the plan, the net present value of reductions
10		in other customer energy costs, net revenue from all electric
11		charging in the service territory, and the societal value of
12		reduced carbon emissions and surface-level pollutants,
13		particularly in environmental justice communities. The
14		calculation of costs and benefits should be based on net
15		impacts, including the impact on customer rates.
16		The Commission shall approve, approve with modifications,
17		or reject the plan within 270 days from the date of filing. The
18		Commission may approve the plan if it finds that the plan will
19		achieve the goals described in this Section and contains the
20		information described in this Section. Proceedings under this
21		Section shall proceed according to the rules provided by
22		Article IX of the Public Utilities Act. Information contained
23		in the approved plan shall be considered part of the record in
24		any Commission proceeding under Section 16-107.6 of the Public
25		Utilities Act, provided that a final order has not been
26		entered prior to the initial filing date. The Beneficial

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1		Electrification Plan shall specifically address, at a minimum,
2		the 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
8		to the rules provided by Article IX of the Public Utilities
9		Act. Information contained in the approved plan shall be
10		considered part of the record in any Commission proceeding
11		under Section 16-107.6 of the Public Utilities Act, provided
12		that a final order has not been entered prior to the initial
13		filing date.
14		(f) The utility shall file an update to the plan on July 1,
15		2024 and every 3 years thereafter. This update shall describe
16		transportation investments made during the prior plan period,
17		investments planned for the following 24 months, and updates
18		to the information required by this Section. Beginning with
19		the first update, the    The utility shall develop the plan in
20		conjunction with the distribution system planning process
21		described in Section 16-105.17, including incorporation of
22		stakeholder feedback from that process.
23		(g) Within 35 days after the utility files its report, the
24		Commission shall, upon its own initiative, open an
25		investigation regarding the utility's plan update to
26		investigate whether the objectives described in this Section

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1		are being achieved. The Commission shall determine whether
2		investment targets should be increased based on achievement of
3		spending goals outlined in the Beneficial Electrification Plan
4		and consistency with outcomes directed in the plan stakeholder
5		workshop report. If the Commission finds, after notice and
6		hearing, that the utility's plan is materially deficient, the
7		Commission shall issue an order requiring the utility to
8		devise a corrective action plan, subject to Commission
9		approval, to bring the plan into compliance with the goals of
10		this Section. The Commission's order shall be entered within
11		270 days after the utility files its annual report. The
12		contents of a plan filed under this Section shall be available
13		for evidence in Commission proceedings. However, omission from
14		an approved plan shall not render any future utility
15		expenditure to be considered unreasonable or imprudent. The
16		Commission may, upon sufficient evidence, allow expenditures
17		that were not part of any particular distribution plan. The
18		Commission shall consider revenues from electric vehicles in
19		the utility's service territory in evaluating the retail rate
20		impact. The retail rate impact from the development of
21		electric vehicle infrastructure shall not exceed 1% per year
22		of the total annual revenue requirements of the utility.
23		(h) In meeting the requirements of this Section, the
24		utility shall demonstrate efforts to increase the use of
25		contractors and electric vehicle charging station installers
26		that meet multiple workforce equity actions, including, but

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1		not limited to:
2		(1) the business is headquartered in or the person
3		resides in an eligible community;
4		(2) the business is majority owned by eligible person
5		or the contractor is an eligible person;
6		(3) the business or person is certified by another
7		municipal, State, federal, or other certification for
8		disadvantaged businesses;
9		(4) the business or person meets the eligibility
10		criteria for a certification program such as:
11		(A) certified under Section 2 of the Business
12		Enterprise for Minorities, Women, and Persons with
13		Disabilities Act;
14		(B) certified by another municipal, State,
15		federal, or other certification for disadvantaged
16		businesses;
17		(C) submits an affidavit showing that the vendor
18		meets the eligibility criteria for a certification
19		program such as those in items (A) and (B);
20		(D) if the vendor is a nonprofit, meets any of the
21		criteria in those in item (A), (B), or (C) with the
22		exception that the nonprofit is not required to meet
23		any criteria related to being a for-profit entity, or
24		is controlled by a board of directors that consists of
25		51% or greater individuals who are equity investment
26		eligible persons; or

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1		(E) ensuring that program implementation
2		contractors and electric vehicle charging station
3		installers pay employees working on electric vehicle
4		charging installations at or above the prevailing wage
5		rate as published by the Department of Labor.
6		Utilities shall establish reporting procedures for vendors
7		that ensure compliance with this subsection, but are
8		structured to avoid, wherever possible, placing an undue
9		administrative burden on vendors.
10		(i) Program data collection.
11		(1) In order to ensure that the benefits provided to
12		Illinois residents and business by the clean energy
13		economy are equitably distributed across the State, it is
14		necessary to accurately measure the applicants and
15		recipients of this Program. The purpose of this paragraph
16		is to require the implementing utilities to collect all
17		data from Program applicants and beneficiaries to track
18		and improve equitable distribution of benefits across
19		Illinois communities. The further purpose is to measure
20		any potential impact of racial discrimination on the
21		distribution of benefits and provide the utilities the
22		information necessary to correct any discrimination
23		through methods consistent with State and federal law.
24		(2) The implementing utilities shall collect
25		demographic and geographic data for each applicant and
26		each person or business awarded benefits or contracts

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1		under this Program.
2		(3) The implementing utilities shall collect the
3		following information from applicants and Program or
4		procurement beneficiaries where applicable:
5		(A) demographic information, including racial or
6		ethnic identity for real persons employed, contracted,
7		or subcontracted through the program;
8		(B) demographic information, including racial or
9		ethnic identity of business owners;
10		(C) geographic location of the residency of real
11		persons or geographic location of the headquarters for
12		businesses; and
13		(D) any other information necessary for the
14		purpose of achieving the purpose of this paragraph.
15		(4) The utility shall publish, at least annually,
16		aggregated information on the demographics of program and
17		procurement applicants and beneficiaries. The utilities
18		shall protect personal and confidential business
19		information as necessary.
20		(5) The utilities shall conduct a regular review
21		process to confirm the accuracy of reported data.
22		(6) On a quarterly basis, utilities shall collect data
23		necessary to ensure compliance with this Section and shall
24		communicate progress toward compliance to program
25		implementation contractors and electric vehicle charging
26		station installation vendors.

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1		(7) Utilities filing Beneficial Electrification Plans
2		under this Section shall report annually to the Illinois
3		Commerce Commission and the General Assembly on how
4		hiring, contracting, job training, and other practices
5		related to its beneficial Beneficial electrification
6		programs enhance the diversity of vendors working on such
7		programs. These reports must include data on vendor and
8		employee diversity.
9		(j) Any Beneficial Electrification Plan under this Section
10		shall terminate on December 31, 2028. Beginning January 1,
11		2029, utilities shall continue to support transportation
12		electrification by maintaining responsibility for the
13		following through the Multi-Year Integrated Grid Plans
14		implemented by electric utilities pursuant to Section
15		16-105.17 of the Public Utilities Act, beginning with the
16		plans that include a time period that is after January 1, 2029:
17		(i) make-ready investments and other programs that
18		facilitate the rapid deployment of charging equipment
19		throughout the State, especially deployment that targets
20		medium-duty and heavy-duty vehicle electrification and
21		multi-unit buildings;
22		(ii) the development and implementation of (1)
23		time-of-use rates and the benefit of the rates for
24		electric vehicle users and for all customers, (2)
25		optimized charging programs to achieve identified savings,
26		and (3) new contracts and compensation for services in the

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1		optimized charging programs, through signals that allow
2		electric vehicle charging to respond to local system
3		conditions, manage critical peak periods, serve as a
4		demand response or peak resource, and maximize renewable
5		energy use and integration into the grid; and
6		(iii) commercial tariffs that utilize alternatives to
7		traditional demand-based rate structures to facilitate
8		charging for light-duty, heavy-duty, and fleet electric
9		vehicles.
10		Utilities shall demonstrate methods of minimizing
11		ratepayer impacts and exempting or minimizing, to the extent
12		possible, low-income ratepayers from the costs associated with
13		facilitating the expansion of electric vehicle charging.
14		(k) (j) The provisions of this Section are severable under
15		Section 1.31 of the Statute on Statutes.
16		(Source: P.A. 102-662, eff. 9-15-21; 102-820, eff. 5-13-22;
17		103-154, eff. 6-30-23.)
18		(20 ILCS 627/55)
19		Sec. 55. Charging rebate program.
20		(a) In order to substantially offset the installation
21		costs of electric vehicle charging infrastructure, beginning
22		July 1, 2022, and continuing as long as funds are available,
23		the Agency shall issue rebates, consistent with the
24		Commission-approved Beneficial Electrification Plans in
25		accordance with Section 45, to public and private

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1		organizations and companies to install and maintain Level 2 or
2		Level 3 charging stations.
3		(b) The Agency shall award rebates or grants that fund up
4		to 80% of the cost of the installation of charging stations.
5		The Agency shall award additional incentives per port for
6		every charging station installed in an eligible community and
7		every charging station located to support eligible persons. In
8		order to be eligible to receive a rebate or grant, the
9		organization or company must submit an application to the
10		Agency and commit to paying the prevailing wage for the
11		installation project. The Agency shall by rule provide
12		application and other programmatic details and requirements,
13		including additional incentives for eligible communities. The
14		Agency may determine per port or project caps based on a review
15		of best practices and stakeholder engagement. The Agency shall
16		accept applications on a rolling basis and shall award rebates
17		or grants within 60 days of each application. The Agency must
18		require that any grant or rebate applicant comply with the
19		requirements of the Prevailing Wage Act for any installation
20		of a charging station for which it seeks a rebate or grant.
21		(c) This Section is repealed on January 1, 2029.
22		(Source: P.A. 102-662, eff. 9-15-21; 102-673, eff. 11-30-21.)
23		Section 90-7. The Energy Transition Act is amended by
24		changing Sections 5-35, 5-40, and 5-60 as follows:

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1		(20 ILCS 730/5-35)
2		(Section scheduled to be repealed on September 15, 2045)
3		Sec. 5-35. Energy Transition Navigators.
4		(a) As used in this Section:
5		"Community-based provider" means a not-for-profit
6		organization that has a history of serving low-wage or
7		low-skilled workers or individuals from economically
8		disadvantaged communities.
9		"Economically disadvantaged community" means areas of one
10		or more census tracts where the average household income does
11		not exceed 80% of the area median income.
12		(b) In order to engage eligible individuals to participate
13		in the Clean Jobs Workforce Network Program, the Illinois
14		Climate Works Preapprenticeship Program, Returning Residents
15		Clean Jobs Program, Clean Energy Contractor Incubator Program,
16		and Clean Energy Primes Contractor Accelerator Program and
17		utilize the services offered under the Energy Transition
18		Barrier Reduction Program, the Department shall, subject to
19		appropriation, contract with community-based providers to
20		serve as Energy Transition Navigators. Energy Transition
21		Navigators shall provide education, outreach, and recruitment
22		services to equity focused populations, prioritizing
23		individuals eligible for the Clean Jobs Workforce Network
24		Program or Illinois Climate Works Preapprenticeship Program,
25		to make sure they are aware of and engaged in the statewide and
26		local workforce development systems. Additional strategies may

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1		include, but are not limited to, recruitment activities and
2		events.
3		(c) For members of equity focused populations,
4		prioritizing individuals eligible for the Clean Jobs Workforce
5		Network Program or Illinois Climate Works Preapprenticeship
6		Program, who may be interested in entrepreneurial pursuits,
7		Energy Transition Navigators may connect these individuals
8		with their area Small Business Development Center, Procurement
9		Technical Assistance Centers, or economic development
10		organization to engage in services, including, but not limited
11		to, business consulting, business planning, regulatory
12		compliance, marketing, training, accessing capital, government
13		bid, and certification assistance.
14		(d) Energy Transition Navigators shall engage equity
15		focused populations, prioritizing individuals eligible for the
16		Clean Jobs Workforce Network Program or Illinois Climate Works
17		Preapprenticeship Program, organizations working with these
18		populations, local workforce innovation boards, and other
19		relevant stakeholders to coordinate outreach initiatives to
20		promote information regarding programs and services offered
21		under the Clean Jobs Workforce Network Program, the Illinois
22		Climate Works Preapprenticeship Program, and the Energy
23		Transition Barrier Reduction Program. Energy Transition
24		Navigators shall provide support where reasonable to
25		individuals and entities applying for these services and
26		programs.

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1		(e) Community education, outreach, and recruitment
2		regarding the Clean Jobs Workforce Network Program, the
3		Illinois Climate Works Preapprenticeship Program, and Energy
4		Transition Barrier Reduction Program shall be targeted to the
5		equity focused populations, prioritizing individuals eligible
6		for the Clean Jobs Workforce Network Program or Illinois
7		Climate Works Preapprenticeship Program.
8		(f) Community-based providers shall partner with
9		educational institutions or organizations working with equity
10		focused populations, local employers, labor unions, and others
11		to identify members of equity focused populations in eligible
12		communities who are unable to advance in their careers due to
13		inadequate skills. Community-based providers shall provide
14		information and consultation to equity focused populations,
15		prioritizing individuals eligible for the Clean Jobs Workforce
16		Network Program or Illinois Climate Works Preapprenticeship
17		Program, on various educational opportunities and supportive
18		services available to them.
19		(g) Community-based providers shall establish partnerships
20		with employers, educational institutions, local economic
21		development organizations, environmental justice
22		organizations, trades groups, labor unions, and entities that
23		provide jobs, including businesses and other nonprofit
24		organizations, to target the skill needs of local industry.
25		The community-based provider shall work with local workforce
26		innovation boards and other relevant partners to develop skill

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1		curriculum and career pathway support for disadvantaged
2		individuals in equity focused populations, prioritizing
3		individuals eligible for the Clean Jobs Workforce Network
4		Program or Illinois Climate Works Preapprenticeship Program,
5		that meets local employers' needs and establishes job
6		placement opportunities after training.
7		(h) Funding for the Program is subject to appropriation
8		from the Energy Transition Assistance Fund. Priority in
9		awarding grants under this Section will be given to
10		organizations that also have experience serving populations
11		impacted by climate change.
12		(i) Each community-based organization that receives
13		funding from the Department as an Energy Transition Navigator
14		shall provide an annual report to the Department by April 1 of
15		each calendar year. The annual report shall include the
16		following information:
17		(1) a description of the community-based
18		organization's recruitment, screening, and training
19		efforts;
20		(2) the number of individuals who apply to,
21		participate in, and complete programs offered through the
22		Energy Transition Workforce Program, broken down by race,
23		gender, age, and location; and
24		(3) any other information deemed necessary by the
25		Department.
26		(Source: P.A. 102-662, eff. 9-15-21.)

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1		(20 ILCS 730/5-40)
2		(Section scheduled to be repealed on September 15, 2045)
3		Sec. 5-40. Illinois Climate Works Preapprenticeship
4		Program.
5		(a) Subject to appropriation, the Department shall
6		develop, and through Regional Administrators administer, the
7		Illinois Climate Works Preapprenticeship Program. The goal of
8		the Illinois Climate Works Preapprenticeship Program is to
9		create a network of hubs throughout the State that will
10		recruit, prescreen, and provide preapprenticeship skills
11		training, for which participants may attend free of charge and
12		receive a stipend, to create a qualified, diverse pipeline of
13		workers who are prepared for careers in the construction and
14		building trades and clean energy jobs opportunities therein.
15		Upon completion of the Illinois Climate Works
16		Preapprenticeship Program, the candidates will be connected to
17		and prepared to successfully complete an apprenticeship
18		program.
19		(b) Each Climate Works Hub that receives funding from the
20		Energy Transition Assistance Fund shall provide an annual
21		report to the Illinois Works Review Panel by April 1 of each
22		calendar year. The annual report shall include the following
23		information:
24		(1) a description of the Climate Works Hub's
25		recruitment, screening, and training efforts, including a

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1		description of training related to construction and
2		building trades opportunities in clean energy jobs;
3		(2) the number of individuals who apply to,
4		participate in, and complete the Climate Works Hub's
5		program, broken down by race, gender, age, and veteran
6		status;
7		(3) the number of the individuals referenced in
8		paragraph (2) of this subsection who are initially
9		accepted and placed into apprenticeship programs in the
10		construction and building trades; and
11		(4) the number of individuals referenced in paragraph
12		(2) of this subsection who remain in apprenticeship
13		programs in the construction and building trades or have
14		become journeymen one calendar year after their placement,
15		as referenced in paragraph (3) of this subsection.
16		(c) Subject to appropriation, the Department shall provide
17		funding to 3 Climate Works Hubs throughout the State,
18		including one to the Illinois Department of Transportation
19		Region 1, one to the Illinois Department of Transportation
20		Regions 2 and 3, and one to the Illinois Department of
21		Transportation Regions 4 and 5. An eligible organization may
22		serve as the designated Climate Works Hub for all 5 regions.
23		Climate Works Hubs shall be awarded grants in multi-year
24		increments not to exceed 36 months. Each grant shall come with
25		a one year initial term, with the Department renewing each
26		year for 2 additional years unless the grantee either declines

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1		to continue or fails to meet reasonable performance measures
2		that consider apprenticeship programs timeframes. The
3		Department may take into account experience and performance as
4		a previous grantee of the Climate Works Hub as part of the
5		selection criteria for subsequent years.
6		(d) Each Climate Works Hub that receives funding from the
7		Energy Transition Assistance Fund shall recruit, prescreen,
8		and provide preapprenticeship training to program
9		participants. Each Climate Works Hub that receives funding
10		from the Energy Transition Assistance Fund shall:
11		(1) in each Hub Site where the applicant pool allows,
12		comply with the following:
13		(A) dedicate at least one-third of Program
14		placements to applicants who reside in a geographic
15		area that is impacted by economic and environmental
16		challenges, defined as an area that is both (i) an R3
17		Area, as defined pursuant to Section 10-40 of the
18		Cannabis Regulation and Tax Act, and (ii) an
19		environmental justice community, as defined by the
20		Illinois Power Agency under 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 justice system, and
3		language barriers, and applicants that are graduates
4		of or currently enrolled in the foster care system;
5		and
6		(B) dedicate at least two-thirds of Program
7		placements to applicants who reside in a geographic
8		area that is impacted by economic or environmental
9		challenges, defined as an area that is either (i) an R3
10		Area, as defined pursuant to Section 10-40 of the
11		Cannabis Regulation and Tax Act, or (ii) an
12		environmental justice community, as defined by the
13		Illinois Power Agency in the Illinois Power Agency
14		Act, excluding any racial or ethnic indicators used by
15		the Agency unless and until the constitutional basis
16		for the inclusion of the factors in determining
17		Program admissions is established; among applicants
18		that satisfy these criteria, preference shall be given
19		to applicants who face barriers to employment,
20		including low educational attainment, prior
21		involvement with the criminal legal system, and
22		language barriers, and applicants that are graduates
23		of or currently enrolled in the foster care system;
24		and
25		(C) prioritize the remaining Program placements
26		for the following:

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1		(i) applicants who are displaced energy
2		workers, as defined in the Energy Community
3		Reinvestment Act;
4		(ii) persons who face barriers to employment,
5		including low educational attainment, prior
6		involvement with the criminal justice system, and
7		language barriers; and
8		(iii) applicants who are graduates of or
9		currently enrolled in the foster care system,
10		regardless of the applicant's area of residence;
11		Each Climate Works Hub that receives funding from
12		the Energy Transition Assistance Fund shall:
13		(1) recruit, prescreen, and provide preapprenticeship
14		training to equity investment eligible persons;
15		(2) provide training information related to
16		opportunities and certifications relevant to clean energy
17		jobs in the construction and building trades; and
18		(3) provide preapprentices with stipends they receive
19		that may vary depending on the occupation the individual
20		is training for.
21		(d-5) Priority shall be given to Climate Works Hubs that
22		have an agreement with North American Building Trades Unions
23		(NABTU) to utilize the Multi-Craft Core Curriculum or
24		successor curriculums.
25		(e) Funding for the Program is subject to appropriation
26		from the Energy Transition Assistance Fund.

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1		(f) The Department shall adopt any rules deemed necessary
2		to implement this Section.
3		(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22;
4		102-1123, eff. 1-27-23.)
5		(20 ILCS 730/5-60)
6		(Section scheduled to be repealed on September 15, 2045)
7		Sec. 5-60. Jobs and Environmental Justice Grant Program.
8		(a) In order to provide upfront capital to support the
9		development of projects, businesses, community organizations,
10		and jobs creating opportunity for historically disadvantaged
11		populations, and to provide seed capital to support community
12		ownership of renewable energy projects, the Department of
13		Commerce and Economic Opportunity shall create and administer
14		a Jobs and Environmental Justice Grant Program. The grant
15		program shall be designed to help remove barriers to project,
16		community, and business development caused by a lack of
17		capital.
18		(b) The grant program shall provide grant awards of up to
19		$1,000,000 per application to support the development of
20		renewable energy resources as defined in Section 1-10 of the
21		Illinois Power Agency Act, and energy efficiency measures as
22		defined in Section 8-103B of the Public Utilities Act. The
23		amount of a grant award shall be based on a project's size and
24		scope. Grants shall be provided upfront, in advance of other
25		incentives, to provide businesses, organizations, and

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1		community groups with capital needed to plan, develop, and
2		execute a project. Grants shall be designed to coordinate with
3		and supplement existing incentive programs, such as the
4		Adjustable Block program, the Illinois Solar for All Program,
5		the community renewable generation projects, and renewable
6		energy procurements as described in the Illinois Power Agency
7		Act, as well as utility energy efficiency measures as
8		described in Section 8-103B of the Public Utilities Act.
9		(c) The Jobs and Environmental Justice Grant Program shall
10		include 2 subprograms:
11		(1) the Equitable Energy Future Grant Program; and
12		(2) the Community Solar Energy Sovereignty Grant
13		Program.
14		(d) The Equitable Energy Future Grant Program is designed
15		to provide seed funding and pre-development funding
16		opportunities for equity eligible contractors and support for
17		compliance with or fulfillment of project labor agreement and
18		prevailing wage requirements in the clean energy economy.
19		(1) The Equitable Energy Future Grant shall be awarded
20		to businesses and nonprofit organizations for costs
21		related to the following activities and project needs:
22		(i) planning and project development, including
23		costs for professional services such as architecture,
24		design, engineering, auditing, consulting, and
25		developer services;
26		(ii) project application, deposit, and approval;

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1		(iii) purchasing and leasing of land;
2		(iv) permitting and zoning;
3		(v) interconnection application costs and fees,
4		studies, and expenses;
5		(vi) equipment and supplies;
6		(vii) community outreach, marketing, and
7		engagement; and
8		(viii) staff and operations expenses; and .
9		(ix) any support needed to comply with or fulfill
10		prevailing wage and project labor agreement
11		requirements in the clean energy economy.
12		(2) Grants shall be awarded to projects that most
13		effectively provide opportunities for equity eligible
14		contractors and equity investment eligible communities,
15		and should consider the following criteria:
16		(i) projects that provide community benefits,
17		which are projects that have one or more of the
18		following characteristics: (A) greater than 50% of the
19		project's energy provided or saved benefits low-income
20		residents, or (B) the project benefits not-for-profit
21		organizations providing services to low-income
22		households, affordable housing owners, or
23		community-based limited liability companies providing
24		services to low-income households;
25		(ii) projects that are located in equity
26		investment eligible communities;

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1		(iii) projects that provide on-the-job training;
2		(iv) projects that contract with contractors who
3		are participating or have participated in the Clean
4		Energy Contractor Incubator Program, Clean Energy
5		Primes Contractor Accelerator Program, or similar
6		programs; and
7		(v) projects employ a minimum of 51% of its
8		workforce from participants and graduates of the Clean
9		Jobs Workforce Network Program, Illinois Climate Works
10		Preapprenticeship Program, and Returning Residents
11		Clean Jobs Training Program; and .
12		(vi) equity eligible contractors and contractors
13		participating in either the Clean Energy Primes
14		Contractor Accelerator Program or the Clean Energy
15		Contractor Incubator Program and that demonstrate
16		support needed on a company or project-specific basis
17		to comply with prevailing wage and project labor
18		agreement requirements in the clean energy economy.
19		(3) Grants shall be awarded to applicants that meet
20		the following criteria:
21		(i) are equity eligible contractors per the equity
22		accountability systems described in subsection (c-10)
23		of Section 1-75 of the Illinois Power Agency Act, or
24		meet the equity building criteria in paragraph (9.5)
25		of subsection (g) of Section 8-103B of the Public
26		Utilities Act; and

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1		(ii) provide demonstrable proof of a historical or
2		future, and persisting, long-term partnership with the
3		community in which the project will be located.
4		(e) The Community Solar Energy Sovereignty Grant Program
5		shall be designed to support the pre-development and
6		development of community solar projects that promote community
7		ownership and energy sovereignty.
8		(1) Grants shall be awarded to applicants that best
9		demonstrate the ability and intent to create community
10		ownership and other local community benefits, including
11		local community wealth building via community renewable
12		generation projects. Grants shall be prioritized to
13		applicants for whom:
14		(i) the proposed project is located in and
15		supporting an equity investment eligible community or
16		communities; and
17		(ii) the proposed project provides additional
18		benefits for participating low-income households.
19		(2) Grant funds shall be awarded to support project
20		pre-development work and may also be awarded to support
21		the development of programs and entities to assist in the
22		long-term governance, management, and maintenance of
23		community solar projects, such as community solar
24		cooperatives. For example, funds may be awarded for:
25		(i) early stage project planning;
26		(ii) project team organization;

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1		(iii) site identification;
2		(iv) organizing a project business model and
3		securing financing;
4		(v) procurement and contracting;
5		(vi) customer outreach and enrollment;
6		(vii) preliminary site assessments;
7		(viii) development of cooperative or community
8		ownership model; and
9		(ix) development of project models that allocate
10		benefits to equity investment eligible communities.
11		(3) Grant recipients shall submit reports to the
12		Department at the end of the grant term on the activities
13		pursued under their grant and any lessons learned for
14		publication on the Department's website so that other
15		energy sovereignty projects may learn from their
16		experience.
17		(4) Eligible applicants shall include community-based
18		organizations, as defined in the Illinois Power Agency's
19		long-term renewable resources procurement plan, or
20		technical service providers working in direct partnership
21		with community-based organizations.
22		(5) The amount of a grant shall be based on a projects'
23		size and scope. Grants shall allow for a significant
24		portion, or the entirety, of the grant value to be made
25		upfront, in advance of other incentives, to ensure
26		businesses and organizations have the capital needed to

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1		plan, develop, and execute a project.
2		(f) The application process for both subprograms shall not
3		be burdensome on applicants, nor require extensive technical
4		knowledge, and shall be able to be completed on less than 4
5		standard letter-sized pages.
6		(g) These grant subprograms may be coordinated with
7		low-interest and no-interest financing opportunities offered
8		through the Clean Energy Jobs and Justice Fund.
9		(h) The grant subprograms may have a budget of up to
10		$41,000,000 $34,000,000 per year. No more than $8,500,000 25%
11		of the allocated budget shall go to the Community Solar Energy
12		Sovereignty Grant Program. No more than $7,000,000 of the
13		allocated budget shall go to financial assistance or technical
14		assistance to support compliance with prevailing wage and
15		project labor agreement requirements.
16		(i) The Department shall endeavor to make expanded
17		Equitable Energy Future Grant Program grants available in line
18		with the timing of projects being constructed that have to
19		comply with newly applicable project labor agreements
20		requirements as a result of this amendatory Act of the 104th
21		General Assembly.
22		(j) The Department may engage contractors or provide
23		grants to nonprofit organizations in order to provide
24		technical assistance as part of this Program to equity
25		eligible contractors and contractors participating in either
26		the Clean Energy Primes Contractor Accelerator Program or

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1		Clean Energy Contractor Incubator Program that need support to
2		comply with and fulfill prevailing wage and project labor
3		agreement requirements in the clean energy economy.
4		(Source: P.A. 102-662, eff. 9-15-21.)
5		Section 90-8. The Nuclear Safety Law of 2004 is amended by
6		changing Sections 8 and 40 as follows:
7		(20 ILCS 3310/8)
8		Sec. 8. Definitions. In this Act:
9		"IEMA-OHS" means the Illinois Emergency Management Agency
10		and Office of Homeland Security, or its successor agency.
11		"Director" means the Director of IEMA-OHS.
12		"Nuclear facilities" means nuclear power plants,
13		facilities housing nuclear test and research reactors,
14		facilities for the chemical conversion of uranium, and
15		facilities for the storage of spent nuclear fuel or high-level
16		radioactive waste.
17		"Nuclear power plant" or "nuclear steam-generating
18		facility" means a thermal power plant in which the energy
19		(heat) released by the fissioning of nuclear fuel is used to
20		boil water to produce steam.
21		"Nuclear power reactor" means an apparatus, other than an
22		atomic weapon, designed or used to sustain nuclear fission in
23		a self-supporting chain reaction.
24		"Small modular reactor" or "SMR" means an advanced nuclear

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1		reactor: (1) with a rated nameplate capacity of 300 electrical
2		megawatts or less; and (2) that may be constructed and
3		operated in combination with similar reactors at a single
4		site.
5		(Source: P.A. 103-569, eff. 6-1-24.)
6		(20 ILCS 3310/40)
7		Sec. 40. Regulation of nuclear safety.
8		(a) The Agency shall have primary responsibility for the
9		coordination and oversight of all State governmental functions
10		concerning the regulation of nuclear power, including low
11		level waste management, environmental monitoring,
12		environmental radiochemical analysis, and transportation of
13		nuclear waste. Functions performed by the Illinois State
14		Police and the Department of Transportation in the area of
15		nuclear safety, on the effective date of this Act, may
16		continue to be performed by these agencies but under the
17		direction of the Agency. All other governmental functions
18		regulating nuclear safety shall be coordinated by the Agency.
19		(b) (Blank). IEMA-OHS, in consultation with the Illinois
20		Environmental Protection Agency, shall adopt rules for the
21		regulation of small modular reactors. The rules shall be
22		adopted by January 1, 2026 and shall include criteria for
23		decommissioning, environmental monitoring, and emergency
24		preparedness. The rules shall include a fee structure to cover
25		IEMA-OHS costs for regulation and inspection. The fee

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1		structure may include fees to cover costs of local government
2		emergency response preparedness through grants administered by
3		IEMA-OHS. None of the rules developed by the Illinois
4		Emergency Management Agency and Office of Homeland Security or
5		any other State agency, board, or commission pursuant to this
6		Act shall be construed to supersede the authority of the U.S.
7		Nuclear Regulatory Commission. The changes made by this
8		amendatory Act of the 103rd General Assembly shall not apply
9		to the uprate, renewal, or subsequent renewal of any license
10		for an existing nuclear power reactor that began operation
11		prior to the effective date of this amendatory Act of the 103rd
12		General Assembly. Any fees collected under this subsection
13		shall be deposited into the Nuclear Safety Emergency
14		Preparedness Fund created pursuant to Section 7 of the
15		Illinois Nuclear Safety Preparedness Act.
16		(c) (Blank). Consistent with federal law and policy
17		statements of and cooperative agreements with the U.S. Nuclear
18		Regulatory Commission with respect to State participation in
19		health and safety regulation of nuclear facilities, and in
20		recognition of the role provided for the states by such laws,
21		policy statements, and cooperative agreements, IEMA-OHS may
22		develop and implement a program for inspections of small
23		modular reactors, both operational and non-operational. The
24		owner of each small modular reactor shall allow access to
25		IEMA-OHS inspectors of all premises and records of the small
26		modular reactor. The IEMA-OHS inspectors shall operate in

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1		accordance with any cooperative agreements executed between
2		IEMA-OHS and the U.S. Nuclear Regulatory Commission. The
3		IEMA-OHS inspectors shall operate in accordance with the
4		security plan for the small modular reactor. IEMA-OHS programs
5		and activities under this Section shall not be inconsistent
6		with federal law.
7		(d) (Blank). IEMA-OHS shall be authorized to conduct
8		activities specified in Section 8 of the Illinois Nuclear
9		Safety Preparedness Act in regard to small modular reactors.
10		(Source: P.A. 102-133, eff. 7-23-21; 102-538, eff. 8-20-21;
11		102-813, eff. 5-13-22; 103-569, eff. 6-1-24.)
12		(20 ILCS 3310/75 rep.)
13		(20 ILCS 3310/90 rep.)
14		Section 90-10. The Nuclear Safety Law of 2004 is amended
15		by repealing Sections 75 and 90.
16		Section 90-11. The Illinois Finance Authority Act is
17		amended by changing Section 801-10 and by adding Section
18		850-20 as follows:
19		(20 ILCS 3501/801-10)
20		Sec. 801-10. Definitions. The following terms, whenever
21		used or referred to in this Act, shall have the following
22		meanings, except in such instances where the context may
23		clearly indicate otherwise:

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1		(a) The term "Authority" means the Illinois Finance
2		Authority created by this Act.
3		(b) The term "project" means an industrial project, clean
4		energy project, energy storage project, conservation project,
5		housing project, public purpose project, higher education
6		project, health facility project, cultural institution
7		project, municipal bond program project, PACE Project,
8		agricultural facility or agribusiness, and "project" may
9		include any combination of one or more of the foregoing
10		undertaken jointly by any person with one or more other
11		persons.
12		(c) The term "public purpose project" means (i) any
13		project or facility, including without limitation land,
14		buildings, structures, machinery, equipment and all other real
15		and personal property, which is authorized or required by law
16		to be acquired, constructed, improved, rehabilitated,
17		reconstructed, replaced or maintained by any unit of
18		government or any other lawful public purpose, including
19		provision of working capital, which is authorized or required
20		by law to be undertaken by any unit of government or (ii) costs
21		incurred and other expenditures, including expenditures for
22		management, investment, or working capital costs, incurred in
23		connection with the reform, consolidation, or implementation
24		of the transition process as described in Articles 22B and 22C
25		of the Illinois Pension Code.
26		(d) The term "industrial project" means the acquisition,

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1		construction, refurbishment, creation, development or
2		redevelopment of any facility, equipment, machinery, real
3		property or personal property for use by any instrumentality
4		of the State or its political subdivisions, for use by any
5		person or institution, public or private, for profit or not
6		for profit, or for use in any trade or business, including, but
7		not limited to, any industrial, manufacturing, clean energy,
8		or commercial enterprise that is located within or outside the
9		State, provided that, with respect to a project involving
10		property located outside the State, the property must be
11		owned, operated, leased or managed by an entity located within
12		the State or an entity affiliated with an entity located
13		within the State, and which is (1) a capital project or clean
14		energy project, including, but not limited to: (i) land and
15		any rights therein, one or more buildings, structures or other
16		improvements, machinery and equipment, whether now existing or
17		hereafter acquired, and whether or not located on the same
18		site or sites; (ii) all appurtenances and facilities
19		incidental to the foregoing, including, but not limited to,
20		utilities, access roads, railroad sidings, track, docking and
21		similar facilities, parking facilities, dockage, wharfage,
22		railroad roadbed, track, trestle, depot, terminal, switching
23		and signaling or related equipment, site preparation and
24		landscaping; and (iii) all non-capital costs and expenses
25		relating thereto or (2) any addition to, renovation,
26		rehabilitation or improvement of a capital project or a clean

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1		energy project, or (3) any activity or undertaking within or
2		outside the State, provided that, with respect to a project
3		involving property located outside the State, the property
4		must be owned, operated, leased or managed by an entity
5		located within the State or an entity affiliated with an
6		entity located within the State, which the Authority
7		determines will aid, assist or encourage economic growth,
8		development or redevelopment within the State or any area
9		thereof, will promote the expansion, retention or
10		diversification of employment opportunities within the State
11		or any area thereof or will aid in stabilizing or developing
12		any industry or economic sector of the State economy. The term
13		"industrial project" also means the production of motion
14		pictures.
15		(e) The term "bond" or "bonds" shall include bonds, notes
16		(including bond, grant or revenue anticipation notes),
17		certificates and/or other evidences of indebtedness
18		representing an obligation to pay money, including refunding
19		bonds.
20		(f) The terms "lease agreement" and "loan agreement" shall
21		mean: (i) an agreement whereby a project acquired by the
22		Authority by purchase, gift or lease is leased to any person,
23		corporation or unit of local government which will use or
24		cause the project to be used as a project as heretofore defined
25		upon terms providing for lease rental payments at least
26		sufficient to pay when due all principal of, interest and

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1		premium, if any, on any bonds of the Authority issued with
2		respect to such project, providing for the maintenance,
3		insuring and operation of the project on terms satisfactory to
4		the Authority, providing for disposition of the project upon
5		termination of the lease term, including purchase options or
6		abandonment of the premises, and such other terms as may be
7		deemed desirable by the Authority, (ii) any agreement pursuant
8		to which the Authority agrees to loan the proceeds of its bonds
9		issued with respect to a project or other funds of the
10		Authority to any person which will use or cause the project to
11		be used as a project as heretofore defined or for any other
12		lawful purpose upon terms providing for loan repayment
13		installments at least sufficient to pay when due all principal
14		of, interest and premium, if any, on any bonds of the
15		Authority, if any, issued with respect to the project or for
16		any other lawful purpose, and providing for maintenance,
17		insurance and other matters as may be deemed desirable by the
18		Authority, or (iii) any financing or refinancing agreement
19		entered into by the Authority under subsection (aa) of Section
20		801-40.
21		(g) The term "financial aid" means the expenditure of
22		Authority funds or funds provided by the Authority through the
23		issuance of its bonds, notes or other evidences of
24		indebtedness or from other sources for the development,
25		construction, acquisition or improvement of a project.
26		(h) The term "person" means an individual, corporation,

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1		unit of government, business trust, estate, trust, partnership
2		or association, 2 or more persons having a joint or common
3		interest, or any other legal entity.
4		(i) The term "unit of government" means the federal
5		government, the State or unit of local government, a school
6		district, or any agency or instrumentality, office, officer,
7		department, division, bureau, commission, college or
8		university thereof.
9		(j) The term "health facility" means: (a) any public or
10		private institution, place, building, or agency required to be
11		licensed under the Hospital Licensing Act; (b) any public or
12		private institution, place, building, or agency required to be
13		licensed under the Nursing Home Care Act, the Specialized
14		Mental Health Rehabilitation Act of 2013, the ID/DD Community
15		Care Act, or the MC/DD Act; (c) any public or licensed private
16		hospital as defined in the Mental Health and Developmental
17		Disabilities Code; (d) any such facility exempted from such
18		licensure when the Director of Public Health attests that such
19		exempted facility meets the statutory definition of a facility
20		subject to licensure; (e) any other public or private health
21		service institution, place, building, or agency which the
22		Director of Public Health attests is subject to certification
23		by the Secretary, U.S. Department of Health and Human Services
24		under the Social Security Act, as now or hereafter amended, or
25		which the Director of Public Health attests is subject to
26		standard-setting by a recognized public or voluntary

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1		accrediting or standard-setting agency; (f) any public or
2		private institution, place, building or agency engaged in
3		providing one or more supporting services to a health
4		facility; (g) any public or private institution, place,
5		building or agency engaged in providing training in the
6		healing arts, including, but not limited to, schools of
7		medicine, dentistry, osteopathy, optometry, podiatry, pharmacy
8		or nursing, schools for the training of x-ray, laboratory or
9		other health care technicians and schools for the training of
10		para-professionals in the health care field; (h) any public or
11		private congregate, life or extended care or elderly housing
12		facility or any public or private home for the aged or infirm,
13		including, without limitation, any Facility as defined in the
14		Life Care Facilities Act; (i) any public or private mental,
15		emotional or physical rehabilitation facility or any public or
16		private educational, counseling, or rehabilitation facility or
17		home, for those persons with a developmental disability, those
18		who are physically ill or disabled, the emotionally disturbed,
19		those persons with a mental illness or persons with learning
20		or similar disabilities or problems; (j) any public or private
21		alcohol, drug or substance abuse diagnosis, counseling
22		treatment or rehabilitation facility, (k) any public or
23		private institution, place, building or agency licensed by the
24		Department of Children and Family Services or which is not so
25		licensed but which the Director of Children and Family
26		Services attests provides child care, child welfare or other

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1		services of the type provided by facilities subject to such
2		licensure; (l) any public or private adoption agency or
3		facility; and (m) any public or private blood bank or blood
4		center. "Health facility" also means a public or private
5		structure or structures suitable primarily for use as a
6		laboratory, laundry, nurses or interns residence or other
7		housing or hotel facility used in whole or in part for staff,
8		employees or students and their families, patients or
9		relatives of patients admitted for treatment or care in a
10		health facility, or persons conducting business with a health
11		facility, physician's facility, surgicenter, administration
12		building, research facility, maintenance, storage or utility
13		facility and all structures or facilities related to any of
14		the foregoing or required or useful for the operation of a
15		health facility, including parking or other facilities or
16		other supporting service structures required or useful for the
17		orderly conduct of such health facility. "Health facility"
18		also means, with respect to a project located outside the
19		State, any public or private institution, place, building, or
20		agency which provides services similar to those described
21		above, provided that such project is owned, operated, leased
22		or managed by a participating health institution located
23		within the State, or a participating health institution
24		affiliated with an entity located within the State.
25		(k) The term "participating health institution" means (i)
26		a private corporation or association or (ii) a public entity

SB0025 Enrolled - 111 - LRB104 07069 BAB 17106 b
1		of this State, in either case authorized by the laws of this
2		State or the applicable state to provide or operate a health
3		facility as defined in this Act and which, pursuant to the
4		provisions of this Act, undertakes the financing, construction
5		or acquisition of a project or undertakes the refunding or
6		refinancing of obligations, loans, indebtedness or advances as
7		provided in this Act.
8		(l) The term "health facility project", means a specific
9		health facility work or improvement to be financed or
10		refinanced (including without limitation through reimbursement
11		of prior expenditures), acquired, constructed, enlarged,
12		remodeled, renovated, improved, furnished, or equipped, with
13		funds provided in whole or in part hereunder, any accounts
14		receivable, working capital, liability or insurance cost or
15		operating expense financing or refinancing program of a health
16		facility with or involving funds provided in whole or in part
17		hereunder, or any combination thereof.
18		(m) The term "bond resolution" means the resolution or
19		resolutions authorizing the issuance of, or providing terms
20		and conditions related to, bonds issued under this Act and
21		includes, where appropriate, any trust agreement, trust
22		indenture, indenture of mortgage or deed of trust providing
23		terms and conditions for such bonds.
24		(n) The term "property" means any real, personal or mixed
25		property, whether tangible or intangible, or any interest
26		therein, including, without limitation, any real estate,

SB0025 Enrolled - 112 - LRB104 07069 BAB 17106 b
1		leasehold interests, appurtenances, buildings, easements,
2		equipment, furnishings, furniture, improvements, machinery,
3		rights of way, structures, accounts, contract rights or any
4		interest therein.
5		(o) The term "revenues" means, with respect to any
6		project, the rents, fees, charges, interest, principal
7		repayments, collections and other income or profit derived
8		therefrom.
9		(p) The term "higher education project" means, in the case
10		of a private institution of higher education, an educational
11		facility to be acquired, constructed, enlarged, remodeled,
12		renovated, improved, furnished, or equipped, or any
13		combination thereof.
14		(q) The term "cultural institution project" means, in the
15		case of a cultural institution, a cultural facility to be
16		acquired, constructed, enlarged, remodeled, renovated,
17		improved, furnished, or equipped, or any combination thereof.
18		(r) The term "educational facility" means any property
19		located within the State, or any property located outside the
20		State, provided that, if the property is located outside the
21		State, it must be owned, operated, leased or managed by an
22		entity located within the State or an entity affiliated with
23		an entity located within the State, in each case constructed
24		or acquired before or after the effective date of this Act,
25		which is or will be, in whole or in part, suitable for the
26		instruction, feeding, recreation or housing of students, the

SB0025 Enrolled - 113 - LRB104 07069 BAB 17106 b
1		conducting of research or other work of a private institution
2		of higher education, the use by a private institution of
3		higher education in connection with any educational, research
4		or related or incidental activities then being or to be
5		conducted by it, or any combination of the foregoing,
6		including, without limitation, any such property suitable for
7		use as or in connection with any one or more of the following:
8		an academic facility, administrative facility, agricultural
9		facility, assembly hall, athletic facility, auditorium,
10		boating facility, campus, communication facility, computer
11		facility, continuing education facility, classroom, dining
12		hall, dormitory, exhibition hall, fire fighting facility, fire
13		prevention facility, food service and preparation facility,
14		gymnasium, greenhouse, health care facility, hospital,
15		housing, instructional facility, laboratory, library,
16		maintenance facility, medical facility, museum, offices,
17		parking area, physical education facility, recreational
18		facility, research facility, stadium, storage facility,
19		student union, study facility, theatre or utility.
20		(s) The term "cultural facility" means any property
21		located within the State, or any property located outside the
22		State, provided that, if the property is located outside the
23		State, it must be owned, operated, leased or managed by an
24		entity located within the State or an entity affiliated with
25		an entity located within the State, in each case constructed
26		or acquired before or after the effective date of this Act,

SB0025 Enrolled - 114 - LRB104 07069 BAB 17106 b
1		which is or will be, in whole or in part, suitable for the
2		particular purposes or needs of a cultural institution,
3		including, without limitation, any such property suitable for
4		use as or in connection with any one or more of the following:
5		an administrative facility, aquarium, assembly hall,
6		auditorium, botanical garden, exhibition hall, gallery,
7		greenhouse, library, museum, scientific laboratory, theater or
8		zoological facility, and shall also include, without
9		limitation, books, works of art or music, animal, plant or
10		aquatic life or other items for display, exhibition or
11		performance. The term "cultural facility" includes buildings
12		on the National Register of Historic Places which are owned or
13		operated by nonprofit entities.
14		(t) "Private institution of higher education" means a
15		not-for-profit educational institution which is not owned by
16		the State or any political subdivision, agency,
17		instrumentality, district or municipality thereof, which is
18		authorized by law to provide a program of education beyond the
19		high school level and which:
20		(1) Admits as regular students only individuals having
21		a certificate of graduation from a high school, or the
22		recognized equivalent of such a certificate;
23		(2) Provides an educational program for which it
24		awards a bachelor's degree, or provides an educational
25		program, admission into which is conditioned upon the
26		prior attainment of a bachelor's degree or its equivalent,

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

SB0025 Enrolled - 116 - LRB104 07069 BAB 17106 b
1		any political subdivision, agency, instrumentality, district
2		or municipality thereof, which institution engages in, or
3		facilitates academic, scientific, educational or professional
4		research or learning in a field or fields of study taught at a
5		private institution of higher education. Academic institutions
6		include, without limitation, libraries, archives, academic,
7		scientific, educational or professional societies,
8		institutions, associations or foundations having such
9		purposes.
10		(v) The term "cultural institution" means any
11		not-for-profit institution which is not owned by the State or
12		any political subdivision, agency, instrumentality, district
13		or municipality thereof, which institution engages in the
14		cultural, intellectual, scientific, educational or artistic
15		enrichment of the people of the State. Cultural institutions
16		include, without limitation, aquaria, botanical societies,
17		historical societies, libraries, museums, performing arts
18		associations or societies, scientific societies and zoological
19		societies.
20		(w) The term "affiliate" means, with respect to financing
21		of an agricultural facility or an agribusiness, any lender,
22		any person, firm or corporation controlled by, or under common
23		control with, such lender, and any person, firm or corporation
24		controlling such lender.
25		(x) The term "agricultural facility" means land, any
26		building or other improvement thereon or thereto, and any

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1		personal properties deemed necessary or suitable for use,
2		whether or not now in existence, in farming, ranching, the
3		production of agricultural commodities (including, without
4		limitation, the products of aquaculture, hydroponics and
5		silviculture) or the treating, processing or storing of such
6		agricultural commodities when such activities are customarily
7		engaged in by farmers as a part of farming and which land,
8		building, improvement or personal property is located within
9		the State, or is located outside the State, provided that, if
10		such property is located outside the State, it must be owned,
11		operated, leased, or managed by an entity located within the
12		State or an entity affiliated with an entity located within
13		the State.
14		(y) The term "lender" with respect to financing of an
15		agricultural facility or an agribusiness, means any federal or
16		State chartered bank, Federal Land Bank, Production Credit
17		Association, Bank for Cooperatives, federal or State chartered
18		savings and loan association or building and loan association,
19		Small Business Investment Company or any other institution
20		qualified within this State to originate and service loans,
21		including, but without limitation to, insurance companies,
22		credit unions and mortgage loan companies. "Lender" also means
23		a wholly owned subsidiary of a manufacturer, seller or
24		distributor of goods or services that makes loans to
25		businesses or individuals, commonly known as a "captive
26		finance company".

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1		(z) The term "agribusiness" means any sole proprietorship,
2		limited partnership, co-partnership, joint venture,
3		corporation or cooperative which operates or will operate a
4		facility located within the State or outside the State,
5		provided that, if any facility is located outside the State,
6		it must be owned, operated, leased, or managed by an entity
7		located within the State or an entity affiliated with an
8		entity located within the State, that is related to the
9		processing of agricultural commodities (including, without
10		limitation, the products of aquaculture, hydroponics and
11		silviculture) or the manufacturing, production or construction
12		of agricultural buildings, structures, equipment, implements,
13		and supplies, or any other facilities or processes used in
14		agricultural production. Agribusiness includes but is not
15		limited to the following:
16		(1) grain handling and processing, including grain
17		storage, drying, treatment, conditioning, mailing and
18		packaging;
19		(2) seed and feed grain development and processing;
20		(3) fruit and vegetable processing, including
21		preparation, canning and packaging;
22		(4) processing of livestock and livestock products,
23		dairy products, poultry and poultry products, fish or
24		apiarian products, including slaughter, shearing,
25		collecting, preparation, canning and packaging;
26		(5) fertilizer and agricultural chemical

SB0025 Enrolled - 119 - LRB104 07069 BAB 17106 b
1		manufacturing, processing, application and supplying;
2		(6) farm machinery, equipment and implement
3		manufacturing and supplying;
4		(7) manufacturing and supplying of agricultural
5		commodity processing machinery and equipment, including
6		machinery and equipment used in slaughter, treatment,
7		handling, collecting, preparation, canning or packaging of
8		agricultural commodities;
9		(8) farm building and farm structure manufacturing,
10		construction and supplying;
11		(9) construction, manufacturing, implementation,
12		supplying or servicing of irrigation, drainage and soil
13		and water conservation devices or equipment;
14		(10) fuel processing and development facilities that
15		produce fuel from agricultural commodities or byproducts;
16		(11) facilities and equipment for processing and
17		packaging agricultural commodities specifically for
18		export;
19		(12) facilities and equipment for forestry product
20		processing and supplying, including sawmilling operations,
21		wood chip operations, timber harvesting operations, and
22		manufacturing of prefabricated buildings, paper, furniture
23		or other goods from forestry products;
24		(13) facilities and equipment for research and
25		development of products, processes and equipment for the
26		production, processing, preparation or packaging of

SB0025 Enrolled - 120 - LRB104 07069 BAB 17106 b
1		agricultural commodities and byproducts.
2		(aa) The term "asset" with respect to financing of any
3		agricultural facility or any agribusiness, means, but is not
4		limited to the following: cash crops or feed on hand;
5		livestock held for sale; breeding stock; marketable bonds and
6		securities; securities not readily marketable; accounts
7		receivable; notes receivable; cash invested in growing crops;
8		net cash value of life insurance; machinery and equipment;
9		cars and trucks; farm and other real estate including life
10		estates and personal residence; value of beneficial interests
11		in trusts; government payments or grants; and any other
12		assets.
13		(bb) The term "liability" with respect to financing of any
14		agricultural facility or any agribusiness shall include, but
15		not be limited to the following: accounts payable; notes or
16		other indebtedness owed to any source; taxes; rent; amounts
17		owed on real estate contracts or real estate mortgages;
18		judgments; accrued interest payable; and any other liability.
19		(cc) The term "Predecessor Authorities" means those
20		authorities as described in Section 845-75.
21		(dd) The term "housing project" means a specific work or
22		improvement located within the State or outside the State and
23		undertaken to provide residential dwelling accommodations,
24		including the acquisition, construction or rehabilitation of
25		lands, buildings and community facilities and in connection
26		therewith to provide nonhousing facilities which are part of

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1		the housing project, including land, buildings, improvements,
2		equipment and all ancillary facilities for use for offices,
3		stores, retirement homes, hotels, financial institutions,
4		service, health care, education, recreation or research
5		establishments, or any other commercial purpose which are or
6		are to be related to a housing development, provided that any
7		work or improvement located outside the State is owned,
8		operated, leased or managed by an entity located within the
9		State, or any entity affiliated with an entity located within
10		the State.
11		(ee) The term "conservation project" means any project
12		including the acquisition, construction, rehabilitation,
13		maintenance, operation, or upgrade that is intended to create
14		or expand open space or to reduce energy usage through
15		efficiency measures. For the purpose of this definition, "open
16		space" has the definition set forth under Section 10 of the
17		Illinois Open Land Trust Act.
18		(ff) The term "significant presence" means the existence
19		within the State of the national or regional headquarters of
20		an entity or group or such other facility of an entity or group
21		of entities where a significant amount of the business
22		functions are performed for such entity or group of entities.
23		(gg) The term "municipal bond issuer" means the State or
24		any other state or commonwealth of the United States, or any
25		unit of local government, school district, agency or
26		instrumentality, office, department, division, bureau,

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1		commission, college or university thereof located in the State
2		or any other state or commonwealth of the United States.
3		(hh) The term "municipal bond program project" means a
4		program for the funding of the purchase of bonds, notes or
5		other obligations issued by or on behalf of a municipal bond
6		issuer.
7		(ii) The term "participating lender" means any trust
8		company, bank, savings bank, credit union, merchant bank,
9		investment bank, broker, investment trust, pension fund,
10		building and loan association, savings and loan association,
11		insurance company, venture capital company, or other
12		institution approved by the Authority which provides a portion
13		of the financing for a project.
14		(jj) The term "loan participation" means any loan in which
15		the Authority co-operates with a participating lender to
16		provide all or a portion of the financing for a project.
17		(kk) The term "PACE Project" means an energy project as
18		defined in Section 5 of the Property Assessed Clean Energy
19		Act.
20		(ll) The term "clean energy" means energy generation that
21		is substantially free (90% or more) of carbon dioxide
22		emissions by design or operations, or that otherwise
23		contributes to the reduction in emissions of environmentally
24		hazardous materials or reduces the volume of environmentally
25		dangerous materials.
26		(mm) The term "clean energy project" means the

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1		acquisition, construction, refurbishment, creation,
2		development or redevelopment of any facility, equipment,
3		machinery, real property, or personal property for use by the
4		State or any unit of local government, school district, agency
5		or instrumentality, office, department, division, bureau,
6		commission, college, or university of the State, for use by
7		any person or institution, public or private, for profit or
8		not for profit, or for use in any trade or business, which the
9		Authority determines will aid, assist, or encourage the
10		development or implementation of clean energy in the State, or
11		as otherwise contemplated by Article 850.
12		(nn) The term "Climate Bank" means the Authority in the
13		exercise of those powers conferred on it by this Act related to
14		clean energy or clean water, drinking water, or wastewater
15		treatment.
16		(oo) "Equity investment eligible community" and "eligible
17		community" mean the geographic areas throughout Illinois that
18		would most benefit from equitable investments by the State
19		designed to combat discrimination. Specifically, the eligible
20		communities shall be defined as the following areas:
21		(1) R3 Areas as established pursuant to Section 10-40
22		of the Cannabis Regulation and Tax Act, where residents
23		have historically been excluded from economic
24		opportunities, including opportunities in the energy
25		sector; and
26		(2) Environmental justice communities, as defined by

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1		the Illinois Power Agency pursuant to the Illinois Power
2		Agency Act, where residents have historically been subject
3		to disproportionate burdens of pollution, including
4		pollution from the energy sector.
5		(pp) "Equity investment eligible person" and "eligible
6		person" mean the persons who would most benefit from equitable
7		investments by the State designed to combat discrimination.
8		Specifically, eligible persons means the following people:
9		(1) persons whose primary residence is in an equity
10		investment eligible community;
11		(2) persons who are graduates of or currently enrolled
12		in the foster care system; or
13		(3) persons who were formerly incarcerated.
14		(qq) "Environmental justice community" means the
15		definition of that term based on existing methodologies and
16		findings used and as may be updated by the Illinois Power
17		Agency and its program administrator in the Illinois Solar for
18		All Program.
19		(rr) "Energy storage project" means a project that uses
20		technology for the storage of energy, including, without
21		limitation, the use of battery or electrochemical storage
22		technology for mobile or stationary applications.
23		(Source: P.A. 104-6, eff. 6-16-25.)
24		(20 ILCS 3501/850-20 new)
25		Sec. 850-20. Thermal Energy Network Revolving Loan and

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1		Financial Assistance Program.
2		(a) As used in this Section:
3		"Program" means the Thermal Energy Network Revolving Loan
4		and Financial Assistance Program established under this
5		Section.
6		"Thermal energy network" means all real estate, fixtures,
7		and personal property operated, owned, used, or to be used for
8		in connection with or to facilitate a community-scale
9		distribution infrastructure project that transfers heat into
10		and out of buildings using non-combusting thermal energy,
11		sourced from zero-emission technologies, including geothermal
12		energy, for the purpose of reducing emissions. "Thermal energy
13		network" includes, but is not limited to, real estate,
14		fixtures, and personal property that is operated, owned, or
15		used by multiple parties and community geothermal systems.
16		(b) In its role as the Climate Bank for the State, the
17		Authority may, subject to available funding, establish and
18		administer a Thermal Energy Network Revolving Loan and
19		Financial Assistance Program. The Program shall provide access
20		to capital for thermal energy network projects that take into
21		consideration the risks involved in the development of shared
22		heating and cooling systems and the required coordination
23		among multiple customers, as well as the benefits of enabling
24		low-cost decarbonization of residential, commercial, and
25		industrial buildings and processes. The Program may provide
26		loans, grants, or other financial assistance for thermal

SB0025 Enrolled - 126 - LRB104 07069 BAB 17106 b
1		energy network projects.
2		(c) The Authority may establish internal accounts
3		necessary to administer the Program, identify sources of
4		public and private funding and financial capital, and develop
5		any requirements or agreements necessary to successfully
6		execute the Program.
7		(d) The Authority shall coordinate and enter into any
8		necessary agreements with the Illinois Commerce Commission to
9		(i) develop and offer funding and financing to thermal energy
10		network pilot projects approved by the Commission under
11		subsection (a) of Section 8-513 of the Public Utilities Act,
12		(ii) receive funds as necessary and as approved by the
13		Commission under subsection (b) of Section 8-513 of the Public
14		Utilities Act, and (iii) establish any requirements necessary
15		to ensure compliance with the objectives of any federal
16		funding sources secured to support the Program.
17		(e) All repayments of loans or other financial assistance
18		made under the Program shall be used or leveraged to provide
19		additional capital to thermal energy network pilot projects
20		that support the clean energy goals of the State, in
21		coordination with any rules established by the Illinois
22		Commerce Commission.
23		(f) The Authority may adopt any resolutions, plans, or
24		rules and fix, determine, charge, or collect any fees,
25		charges, costs, and expenses necessary to administer the
26		Program under this Section.

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1		Section 90-12. The Illinois Power Agency Act is amended by
2		changing Sections 1-10, 1-20, 1-56, 1-75, and 1-125 as
3		follows:
4		(20 ILCS 3855/1-10)
5		Sec. 1-10. Definitions.
6		"Agency" means the Illinois Power Agency.
7		"Agency loan agreement" means any agreement pursuant to
8		which the Illinois Finance Authority agrees to loan the
9		proceeds of revenue bonds issued with respect to a project to
10		the Agency upon terms providing for loan repayment
11		installments at least sufficient to pay when due all principal
12		of, interest and premium, if any, on those revenue bonds, and
13		providing for maintenance, insurance, and other matters in
14		respect of the project.
15		"Authority" means the Illinois Finance Authority.
16		"Brownfield site photovoltaic project" means photovoltaics
17		that are either:
18		(1) interconnected to an electric utility as defined
19		in this Section, a municipal utility as defined in this
20		Section, a public utility as defined in Section 3-105 of
21		the Public Utilities Act, or an electric cooperative as
22		defined in Section 3-119 of the Public Utilities Act and
23		located at a site that is regulated by any of the following
24		entities under the following programs:

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1		(A) the United States Environmental Protection
2		Agency under the federal Comprehensive Environmental
3		Response, Compensation, and Liability Act of 1980, as
4		amended;
5		(B) the United States Environmental Protection
6		Agency under the Corrective Action Program of the
7		federal Resource Conservation and Recovery Act, as
8		amended;
9		(C) the Illinois Environmental Protection Agency
10		under the Illinois Site Remediation Program; or
11		(D) the Illinois Environmental Protection Agency
12		under the Illinois Solid Waste Program; or
13		(2) located at the site of a coal mine that has
14		permanently ceased coal production, permanently halted any
15		re-mining operations, and is no longer accepting any coal
16		combustion residues; has both completed all clean-up and
17		remediation obligations under the federal Surface Mining
18		and Reclamation Act of 1977 and all applicable Illinois
19		rules and any other clean-up, remediation, or ongoing
20		monitoring to safeguard the health and well-being of the
21		people of the State of Illinois, as well as demonstrated
22		compliance with all applicable federal and State
23		environmental rules and regulations, including, but not
24		limited, to 35 Ill. Adm. Code Part 845 and any rules for
25		historic fill of coal combustion residuals, including any
26		rules finalized in Subdocket A of Illinois Pollution

SB0025 Enrolled - 129 - LRB104 07069 BAB 17106 b
1		Control Board docket R2020-019.
2		"Clean coal facility" means an electric generating
3		facility that uses primarily coal as a feedstock and that
4		captures and sequesters carbon dioxide emissions at the
5		following levels: at least 50% of the total carbon dioxide
6		emissions that the facility would otherwise emit if, at the
7		time construction commences, the facility is scheduled to
8		commence operation before 2016, at least 70% of the total
9		carbon dioxide emissions that the facility would otherwise
10		emit if, at the time construction commences, the facility is
11		scheduled to commence operation during 2016 or 2017, and at
12		least 90% of the total carbon dioxide emissions that the
13		facility would otherwise emit if, at the time construction
14		commences, the facility is scheduled to commence operation
15		after 2017. The power block of the clean coal facility shall
16		not exceed allowable emission rates for sulfur dioxide,
17		nitrogen oxides, carbon monoxide, particulates and mercury for
18		a natural gas-fired combined-cycle facility the same size as
19		and in the same location as the clean coal facility at the time
20		the clean coal facility obtains an approved air permit. All
21		coal used by a clean coal facility shall have high volatile
22		bituminous rank and greater than 1.7 pounds of sulfur per
23		million Btu content, unless the clean coal facility does not
24		use gasification technology and was operating as a
25		conventional coal-fired electric generating facility on June
26		1, 2009 (the effective date of Public Act 95-1027).

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1		"Clean coal SNG brownfield facility" means a facility that
2		(1) has commenced construction by July 1, 2015 on an urban
3		brownfield site in a municipality with at least 1,000,000
4		residents; (2) uses a gasification process to produce
5		substitute natural gas; (3) uses coal as at least 50% of the
6		total feedstock over the term of any sourcing agreement with a
7		utility and the remainder of the feedstock may be either
8		petroleum coke or coal, with all such coal having a high
9		bituminous rank and greater than 1.7 pounds of sulfur per
10		million Btu content unless the facility reasonably determines
11		that it is necessary to use additional petroleum coke to
12		deliver additional consumer savings, in which case the
13		facility shall use coal for at least 35% of the total feedstock
14		over the term of any sourcing agreement; and (4) captures and
15		sequesters at least 85% of the total carbon dioxide emissions
16		that the facility would otherwise emit.
17		"Clean coal SNG facility" means a facility that uses a
18		gasification process to produce substitute natural gas, that
19		sequesters at least 90% of the total carbon dioxide emissions
20		that the facility would otherwise emit, that uses at least 90%
21		coal as a feedstock, with all such coal having a high
22		bituminous rank and greater than 1.7 pounds of sulfur per
23		million Btu content, and that has a valid and effective permit
24		to construct emission sources and air pollution control
25		equipment and approval with respect to the federal regulations
26		for Prevention of Significant Deterioration of Air Quality

SB0025 Enrolled - 131 - LRB104 07069 BAB 17106 b
1		(PSD) for the plant pursuant to the federal Clean Air Act;
2		provided, however, a clean coal SNG brownfield facility shall
3		not be a clean coal SNG facility.
4		"Clean energy" means energy generation that is 90% or
5		greater free of carbon dioxide emissions.
6		"Commission" means the Illinois Commerce Commission.
7		"Community renewable generation project" means an electric
8		generating facility that:
9		(1) is powered by wind, solar thermal energy,
10		photovoltaic cells or panels, biodiesel, crops and
11		untreated and unadulterated organic waste biomass, and
12		hydropower that does not involve new construction of dams;
13		(2) is interconnected at the distribution system level
14		of an electric utility as defined in this Section, a
15		municipal utility as defined in this Section that owns or
16		operates electric distribution facilities, a public
17		utility as defined in Section 3-105 of the Public
18		Utilities Act, or an electric cooperative, as defined in
19		Section 3-119 of the Public Utilities Act;
20		(3) credits the value of electricity generated by the
21		facility to the subscribers of the facility; and
22		(4) is limited in nameplate capacity to less than or
23		equal to 10,000 5,000 kilowatts.
24		"Costs incurred in connection with the development and
25		construction of a facility" means:
26		(1) the cost of acquisition of all real property,

SB0025 Enrolled - 132 - LRB104 07069 BAB 17106 b
1		fixtures, and improvements in connection therewith and
2		equipment, personal property, and other property, rights,
3		and easements acquired that are deemed necessary for the
4		operation and maintenance of the facility;
5		(2) financing costs with respect to bonds, notes, and
6		other evidences of indebtedness of the Agency;
7		(3) all origination, commitment, utilization,
8		facility, placement, underwriting, syndication, credit
9		enhancement, and rating agency fees;
10		(4) engineering, design, procurement, consulting,
11		legal, accounting, title insurance, survey, appraisal,
12		escrow, trustee, collateral agency, interest rate hedging,
13		interest rate swap, capitalized interest, contingency, as
14		required by lenders, and other financing costs, and other
15		expenses for professional services; and
16		(5) the costs of plans, specifications, site study and
17		investigation, installation, surveys, other Agency costs
18		and estimates of costs, and other expenses necessary or
19		incidental to determining the feasibility of any project,
20		together with such other expenses as may be necessary or
21		incidental to the financing, insuring, acquisition, and
22		construction of a specific project and starting up,
23		commissioning, and placing that project in operation.
24		"Delivery services" has the same definition as found in
25		Section 16-102 of the Public Utilities Act.
26		"Delivery year" means the consecutive 12-month period

SB0025 Enrolled - 133 - LRB104 07069 BAB 17106 b
1		beginning June 1 of a given year and ending May 31 of the
2		following year.
3		"Department" means the Department of Commerce and Economic
4		Opportunity.
5		"Director" means the Director of the Illinois Power
6		Agency.
7		"Demand response Demand-response" means measures that
8		decrease peak electricity demand or shift demand from peak to
9		off-peak periods.
10		"Distributed renewable energy generation device" means a
11		device that is:
12		(1) powered by wind, solar thermal energy,
13		photovoltaic cells or panels, biodiesel, crops and
14		untreated and unadulterated organic waste biomass, tree
15		waste, and hydropower that does not involve new
16		construction of dams, waste heat to power systems, or
17		qualified combined heat and power systems;
18		(2) interconnected at the distribution system level of
19		either an electric utility as defined in this Section, a
20		municipal utility as defined in this Section that owns or
21		operates electric distribution facilities, or a rural
22		electric cooperative as defined in Section 3-119 of the
23		Public Utilities Act;
24		(3) located on the customer side of the customer's
25		electric meter and is primarily used to offset that
26		customer's electricity load; and

SB0025 Enrolled - 134 - LRB104 07069 BAB 17106 b
1		(4) (blank).
2		"Energy efficiency" means measures that reduce the amount
3		of electricity or natural gas consumed in order to achieve a
4		given end use. "Energy efficiency" includes voltage
5		optimization measures that optimize the voltage at points on
6		the electric distribution voltage system and thereby reduce
7		electricity consumption by electric customers' end use
8		devices. "Energy efficiency" also includes measures that
9		reduce the total Btus of electricity, natural gas, and other
10		fuels needed to meet the end use or uses.
11		"Energy storage system" has the meaning given to that term
12		in Section 16-135 of the Public Utilities Act. "Energy storage
13		system" does not include technologies that require combustion.
14		"Energy storage resources" means the operational output or
15		capabilities of energy storage systems. "Energy storage
16		resources" includes, but is not limited to, energy, capacity,
17		and energy storage credits.
18		"Electric utility" has the same definition as found in
19		Section 16-102 of the Public Utilities Act.
20		"Equity investment eligible community" or "eligible
21		community" are synonymous and mean the geographic areas
22		throughout Illinois which would most benefit from equitable
23		investments by the State designed to combat discrimination.
24		Specifically, the eligible communities shall be defined as the
25		following areas:
26		(1) R3 Areas as established pursuant to Section 10-40

SB0025 Enrolled - 135 - LRB104 07069 BAB 17106 b
1		of the Cannabis Regulation and Tax Act, where residents
2		have historically been excluded from economic
3		opportunities, including opportunities in the energy
4		sector; and
5		(2) environmental justice communities, as defined by
6		the Illinois Power Agency pursuant to the Illinois Power
7		Agency Act, where residents have historically been subject
8		to disproportionate burdens of pollution, including
9		pollution from the energy sector.
10		"Equity eligible persons" or "eligible persons" means
11		persons who would most benefit from equitable investments by
12		the State designed to combat discrimination, specifically:
13		(1) persons who graduate from or are current or former
14		participants in the Clean Jobs Workforce Network Program,
15		the Clean Energy Contractor Incubator Program, the
16		Illinois Climate Works Preapprenticeship Program,
17		Returning Residents Clean Jobs Training Program, or the
18		Clean Energy Primes Contractor Accelerator Program, and
19		the solar training pipeline and multi-cultural jobs
20		program created in paragraphs (1) and (3) of subsection
21		(a) (a)(1) and (a)(3) of Section 16-108.12 16-208.12 of
22		the Public Utilities Act;
23		(2) persons who are graduates of or currently enrolled
24		in the foster care system;
25		(3) persons who were formerly incarcerated;
26		(4) persons whose primary residence is in an equity

SB0025 Enrolled - 136 - LRB104 07069 BAB 17106 b
1		investment eligible community.
2		"Equity eligible contractor" means a business that is
3		majority-owned by eligible persons, or a nonprofit or
4		cooperative that is majority-governed by eligible persons, or
5		is a natural person that is an eligible person offering
6		personal services as an independent contractor.
7		"Facility" means an electric generating unit or a
8		co-generating unit that produces electricity along with
9		related equipment necessary to connect the facility to an
10		electric transmission or distribution system.
11		"General contractor" means the entity or organization with
12		main responsibility for the building of a construction project
13		and who is the party signing the prime construction contract
14		for the project.
15		"Governmental aggregator" means one or more units of local
16		government that individually or collectively procure
17		electricity to serve residential retail electrical loads
18		located within its or their jurisdiction.
19		"High voltage direct current converter station" means the
20		collection of equipment that converts direct current energy
21		from a high voltage direct current transmission line into
22		alternating current using Voltage Source Conversion technology
23		and that is interconnected with transmission or distribution
24		assets located in Illinois.
25		"High voltage direct current renewable energy credit"
26		means a renewable energy credit associated with a renewable

SB0025 Enrolled - 137 - LRB104 07069 BAB 17106 b
1		energy resource where the renewable energy resource has
2		entered into a contract to transmit the energy associated with
3		such renewable energy credit over high voltage direct current
4		transmission facilities.
5		"High voltage direct current transmission facilities"
6		means the collection of installed equipment that converts
7		alternating current energy in one location to direct current
8		and transmits that direct current energy to a high voltage
9		direct current converter station using Voltage Source
10		Conversion technology. "High voltage direct current
11		transmission facilities" includes the high voltage direct
12		current converter station itself and associated high voltage
13		direct current transmission lines. Notwithstanding the
14		preceding, after September 15, 2021 (the effective date of
15		Public Act 102-662), an otherwise qualifying collection of
16		equipment does not qualify as high voltage direct current
17		transmission facilities unless (1) its developer entered into
18		a project labor agreement, is capable of transmitting
19		electricity at 525kv with an Illinois converter station
20		located and interconnected in the region of the PJM
21		Interconnection, LLC, and the system does not operate as a
22		public utility, as that term is defined in Section 3-105 of the
23		Public Utilities Act, serving more than 100,000 customers as
24		of January 1, 2021; or (2) its developer has entered into a
25		project labor agreement prior to construction, the project is
26		capable of transmitting electricity at 525 kilovolts or above,

SB0025 Enrolled - 138 - LRB104 07069 BAB 17106 b
1		and the project has a converter station that is located in this
2		State or in a state adjacent to this State and is
3		interconnected to PJM Interconnection, LLC, the Midcontinent
4		Independent System Operator, Inc., or their successor.
5		"Hydropower" means any method of electricity generation or
6		storage that results from the flow of water, including
7		impoundment facilities, diversion facilities, and pumped
8		storage facilities.
9		"Index price" means the real-time energy settlement price
10		at the applicable Illinois trading hub, such as PJM-NIHUB or
11		MISO-IL, for a given settlement period.
12		"Indexed renewable energy credit" means a tradable credit
13		that represents the environmental attributes of one megawatt
14		hour of energy produced from a renewable energy resource, the
15		price of which shall be calculated by subtracting the strike
16		price offered by a new utility-scale wind project or a new
17		utility-scale photovoltaic project from the index price in a
18		given settlement period.
19		"Indexed renewable energy credit counterparty" has the
20		same meaning as "public utility" as defined in Section 3-105
21		of the Public Utilities Act.
22		"Local government" means a unit of local government as
23		defined in Section 1 of Article VII of the Illinois
24		Constitution.
25		"Modernized" or "retooled" means the construction, repair,
26		maintenance, or significant expansion of turbines and existing

SB0025 Enrolled - 139 - LRB104 07069 BAB 17106 b
1		hydropower dams.
2		"Municipality" means a city, village, or incorporated
3		town.
4		"Municipal utility" means a public utility owned and
5		operated by any subdivision or municipal corporation of this
6		State.
7		"Nameplate capacity" means the aggregate inverter
8		nameplate capacity in kilowatts AC.
9		"Person" means any natural person, firm, partnership,
10		corporation, either domestic or foreign, company, association,
11		limited liability company, joint stock company, or association
12		and includes any trustee, receiver, assignee, or personal
13		representative thereof.
14		"Project" means the planning, bidding, and construction of
15		a facility.
16		"Project labor agreement" means a pre-hire collective
17		bargaining agreement that covers all terms and conditions of
18		employment on a specific construction project and must include
19		the following:
20		(1) provisions establishing the minimum hourly wage
21		for each class of labor organization employee;
22		(2) provisions establishing the benefits and other
23		compensation for each class of labor organization
24		employee;
25		(3) provisions establishing that no strike or disputes
26		will be engaged in by the labor organization employees;

SB0025 Enrolled - 140 - LRB104 07069 BAB 17106 b
1		(4) provisions establishing that no lockout or
2		disputes will be engaged in by the general contractor
3		building the project; and
4		(5) provisions for minorities and women, as defined
5		under the Business Enterprise for Minorities, Women, and
6		Persons with Disabilities Act, setting forth goals for
7		apprenticeship hours to be performed by minorities and
8		women and setting forth goals for total hours to be
9		performed by underrepresented minorities and women.
10		A labor organization and the general contractor building
11		the project shall have the authority to include other terms
12		and conditions as they deem necessary.
13		"Public utility" has the same definition as found in
14		Section 3-105 of the Public Utilities Act.
15		"Qualified combined heat and power systems" means systems
16		that, either simultaneously or sequentially, produce
17		electricity and useful thermal energy from a single fuel
18		source. Such systems are eligible for "renewable energy
19		credits" in an amount equal to its total energy output where a
20		renewable fuel is consumed or in an amount equal to the net
21		reduction in nonrenewable fuel consumed on a total energy
22		output basis.
23		"Real property" means any interest in land together with
24		all structures, fixtures, and improvements thereon, including
25		lands under water and riparian rights, any easements,
26		covenants, licenses, leases, rights-of-way, uses, and other

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1		interests, together with any liens, judgments, mortgages, or
2		other claims or security interests related to real property.
3		"Renewable energy credit" means a tradable credit that
4		represents the environmental attributes of one megawatt hour
5		of energy produced from a renewable energy resource.
6		"Renewable energy resources" includes energy and its
7		associated renewable energy credit or renewable energy credits
8		from wind, solar thermal energy, photovoltaic cells and
9		panels, biodiesel, anaerobic digestion, crops and untreated
10		and unadulterated organic waste biomass, and hydropower that
11		does not involve new construction of dams, waste heat to power
12		systems, or qualified combined heat and power systems, or
13		geothermal heating and cooling systems that qualify for the
14		Geothermal Homes and Businesses Program. For purposes of this
15		Act, landfill gas produced in the State is considered a
16		renewable energy resource. "Renewable energy resources" does
17		not include the incineration or burning of tires, garbage,
18		general household, institutional, and commercial waste,
19		industrial lunchroom or office waste, landscape waste,
20		railroad crossties, utility poles, or construction or
21		demolition debris, other than untreated and unadulterated
22		waste wood. "Renewable energy resources" also includes high
23		voltage direct current renewable energy credits and the
24		associated energy converted to alternating current by a high
25		voltage direct current converter station to the extent that:
26		(1) the generator of such renewable energy resource contracted

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1		with a third party to transmit the energy over the high voltage
2		direct current transmission facilities, and (2) the
3		third-party contracting for delivery of renewable energy
4		resources over the high voltage direct current transmission
5		facilities have ownership rights over the unretired associated
6		high voltage direct current renewable energy credit.
7		"Retail customer" has the same definition as found in
8		Section 16-102 of the Public Utilities Act.
9		"Revenue bond" means any bond, note, or other evidence of
10		indebtedness issued by the Authority, the principal and
11		interest of which is payable solely from revenues or income
12		derived from any project or activity of the Agency.
13		"Sequester" means permanent storage of carbon dioxide by
14		injecting it into a saline aquifer, a depleted gas reservoir,
15		or an oil reservoir, directly or through an enhanced oil
16		recovery process that may involve intermediate storage,
17		regardless of whether these activities are conducted by a
18		clean coal facility, a clean coal SNG facility, a clean coal
19		SNG brownfield facility, or a party with which a clean coal
20		facility, clean coal SNG facility, or clean coal SNG
21		brownfield facility has contracted for such purposes.
22		"Service area" has the same definition as found in Section
23		16-102 of the Public Utilities Act.
24		"Settlement period" means the period of time utilized by
25		MISO and PJM and their successor organizations as the basis
26		for settlement calculations in the real-time energy market.

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1		"Sourcing agreement" means (i) in the case of an electric
2		utility, an agreement between the owner of a clean coal
3		facility and such electric utility, which agreement shall have
4		terms and conditions meeting the requirements of paragraph (3)
5		of subsection (d) of Section 1-75, (ii) in the case of an
6		alternative retail electric supplier, an agreement between the
7		owner of a clean coal facility and such alternative retail
8		electric supplier, which agreement shall have terms and
9		conditions meeting the requirements of Section 16-115(d)(5) of
10		the Public Utilities Act, and (iii) in case of a gas utility,
11		an agreement between the owner of a clean coal SNG brownfield
12		facility and the gas utility, which agreement shall have the
13		terms and conditions meeting the requirements of subsection
14		(h-1) of Section 9-220 of the Public Utilities Act.
15		"Strike price" means a contract price for energy and
16		renewable energy credits from a new utility-scale wind project
17		or a new utility-scale photovoltaic project.
18		"Subscriber" means a person who (i) takes delivery service
19		from an electric utility, and (ii) has a subscription of no
20		less than 200 watts to a community renewable generation
21		project that is located in the electric utility's service
22		area. No subscriber's subscriptions may total more than 40% of
23		the nameplate capacity of an individual community renewable
24		generation project. Entities that are affiliated by virtue of
25		a common parent shall not represent multiple subscriptions
26		that total more than 40% of the nameplate capacity of an

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1		individual community renewable generation project.
2		"Subscription" means an interest in a community renewable
3		generation project expressed in kilowatts, which is sized
4		primarily to offset part or all of the subscriber's
5		electricity usage.
6		"Substitute natural gas" or "SNG" means a gas manufactured
7		by gasification of hydrocarbon feedstock, which is
8		substantially interchangeable in use and distribution with
9		conventional natural gas.
10		"Total resource cost test" or "TRC test" means a standard
11		that is met if, for an investment in energy efficiency or
12		demand-response measures, the benefit-cost ratio is greater
13		than one. The benefit-cost ratio is the ratio of the net
14		present value of the total benefits of the program to the net
15		present value of the total costs as calculated over the
16		lifetime of the measures. A total resource cost test compares
17		the sum of avoided electric utility costs, representing the
18		benefits that accrue to the system and the participant in the
19		delivery of those efficiency measures and including avoided
20		costs associated with reduced use of natural gas or other
21		fuels, avoided costs associated with reduced water
22		consumption, and avoided costs associated with reduced
23		operation and maintenance costs, and avoided societal costs
24		associated with reductions in greenhouse gas emissions, as
25		well as other quantifiable societal benefits, to the sum of
26		all incremental costs of end-use measures that are implemented

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1		due to the program (including both utility and participant
2		contributions), plus costs to administer, deliver, and
3		evaluate each demand-side program, to quantify the net savings
4		obtained by substituting the demand-side program for supply
5		resources. The societal costs associated with greenhouse gas
6		emissions shall be $200 per short ton, expressed in 2025
7		dollars or the most recently approved estimate developed by
8		the federal government using a real discount rate consistent
9		with long-term Treasury bond yields, whichever is greater.
10		Changes in greenhouse gas emissions due to changes in
11		electricity consumption shall be estimated using long-run
12		marginal emissions rates developed by the National Renewable
13		Energy Laboratory's Cambium model or other Illinois-specific
14		modeling of comparable analytical rigor. In calculating
15		avoided costs of power and energy that an electric utility
16		would otherwise have had to acquire, reasonable estimates
17		shall be included of financial costs likely to be imposed by
18		future regulations and legislation on emissions of greenhouse
19		gases. In discounting future societal costs and benefits for
20		the purpose of calculating net present values, a societal
21		discount rate based on actual, long-term Treasury bond yields
22		should be used. Notwithstanding anything to the contrary, the
23		TRC test shall not include or take into account a calculation
24		of market price suppression effects or demand reduction
25		induced price effects.
26		"Utility-scale solar project" means an electric generating

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1		facility that:
2		(1) generates electricity using photovoltaic cells;
3		and
4		(2) has a nameplate capacity that is greater than
5		5,000 kilowatts alternating current (AC).
6		"Utility-scale wind project" means an electric generating
7		facility that:
8		(1) generates electricity using wind; and
9		(2) has a nameplate capacity that is greater than
10		5,000 kilowatts.
11		"Waste Heat to Power Systems" means systems that capture
12		and generate electricity from energy that would otherwise be
13		lost to the atmosphere without the use of additional fuel.
14		"Zero emission credit" means a tradable credit that
15		represents the environmental attributes of one megawatt hour
16		of energy produced from a zero emission facility.
17		"Zero emission facility" means a facility that: (1) is
18		fueled by nuclear power; and (2) is interconnected with PJM
19		Interconnection, LLC or the Midcontinent Independent System
20		Operator, Inc., or their successors.
21		(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23;
22		103-380, eff. 1-1-24.)
23		(20 ILCS 3855/1-20)
24		Sec. 1-20. General powers and duties of the Agency.
25		(a) The Agency is authorized to do each of the following:

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1		(1) Develop electricity procurement plans to ensure
2		adequate, reliable, affordable, efficient, and
3		environmentally sustainable electric service at the lowest
4		total cost over time, taking into account any benefits of
5		price stability, for electric utilities that on December
6		31, 2005 provided electric service to at least 100,000
7		customers in Illinois and for small multi-jurisdictional
8		electric utilities that (A) on December 31, 2005 served
9		less than 100,000 customers in Illinois and (B) request a
10		procurement plan for their Illinois jurisdictional load.
11		Except as provided in paragraph (1.5) of this subsection
12		(a), the electricity procurement plans shall be updated on
13		an annual basis and shall include electricity generated
14		from renewable resources sufficient to achieve the
15		standards specified in this Act. Beginning with the
16		delivery year commencing June 1, 2017, develop procurement
17		plans to include zero emission credits generated from zero
18		emission facilities sufficient to achieve the standards
19		specified in this Act. Beginning with the delivery year
20		commencing on June 1, 2022, the Agency is authorized to
21		develop carbon mitigation credit procurement plans to
22		include carbon mitigation credits generated from
23		carbon-free energy resources sufficient to achieve the
24		standards specified in this Act.
25		(1.5) Develop a long-term renewable resources
26		procurement plan in accordance with subsection (c) of

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1		Section 1-75 of this Act for renewable energy credits in
2		amounts sufficient to achieve the standards specified in
3		this Act for delivery years commencing June 1, 2017 and
4		for the programs and renewable energy credits specified in
5		Section 1-56 of this Act. Electricity procurement plans
6		for delivery years commencing after May 31, 2017, shall
7		not include procurement of renewable energy resources.
8		(2) Conduct competitive procurement processes to
9		procure the supply resources identified in the electricity
10		procurement plan, pursuant to Section 16-111.5 of the
11		Public Utilities Act, and, for the delivery year
12		commencing June 1, 2017, conduct procurement processes to
13		procure zero emission credits from zero emission
14		facilities, under subsection (d-5) of Section 1-75 of this
15		Act. For the delivery year commencing June 1, 2022, the
16		Agency is authorized to conduct procurement processes to
17		procure carbon mitigation credits from carbon-free energy
18		resources, under subsection (d-10) of Section 1-75 of this
19		Act.
20		(2.5) Beginning with the procurement for the 2017
21		delivery year, conduct competitive procurement processes
22		and implement programs to procure renewable energy credits
23		identified in the long-term renewable resources
24		procurement plan developed and approved under subsection
25		(c) of Section 1-75 of this Act and Section 16-111.5 of the
26		Public Utilities Act.

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1		(2.10) Oversee the procurement by electric utilities
2		that served more than 300,000 customers in this State as
3		of January 1, 2019 of renewable energy credits from new
4		renewable energy facilities to be installed, along with
5		energy storage facilities, at or adjacent to the sites of
6		electric generating facilities that burned coal as their
7		primary fuel source as of January 1, 2016 in accordance
8		with subsection (c-5) of Section 1-75 of this Act.
9		(2.15) Oversee the procurement by electric utilities
10		of renewable energy credits from newly modernized or
11		retooled hydropower dams or dams that have been converted
12		to support hydropower generation.
13		(3) Develop electric generation and co-generation
14		facilities that use indigenous coal or renewable
15		resources, or both, financed with bonds issued by the
16		Illinois Finance Authority.
17		(4) Supply electricity from the Agency's facilities at
18		cost to one or more of the following: municipal electric
19		systems, governmental aggregators, or rural electric
20		cooperatives in Illinois.
21		(5) Develop a long-term energy storage resources
22		procurement plan and conduct competitive procurement
23		processes in accordance with subsection (d-20) of Section
24		1-75.
25		(b) Except as otherwise limited by this Act, the Agency
26		has all of the powers necessary or convenient to carry out the

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

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

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

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1		(16) To enter into management agreements for the
2		operation of any of the property or facilities owned by
3		the Agency.
4		(17) To enter into an agreement to transfer and to
5		transfer any land, facilities, fixtures, or equipment of
6		the Agency to one or more municipal electric systems,
7		governmental aggregators, or rural electric agencies or
8		cooperatives, for such consideration and upon such terms
9		as the Agency may determine to be in the best interest of
10		the residents of Illinois.
11		(18) To enter upon any lands and within any building
12		whenever in its judgment it may be necessary for the
13		purpose of making surveys and examinations to accomplish
14		any purpose authorized by this Act.
15		(19) To maintain an office or offices at such place or
16		places in the State as it may determine.
17		(20) To request information, and to make any inquiry,
18		investigation, survey, or study that the Agency may deem
19		necessary to enable it effectively to carry out the
20		provisions of this Act.
21		(21) To accept and expend appropriations.
22		(22) To engage in any activity or operation that is
23		incidental to and in furtherance of efficient operation to
24		accomplish the Agency's purposes, including hiring
25		employees that the Director deems essential for the
26		operations of the Agency.

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1		(23) To adopt, revise, amend, and repeal rules with
2		respect to its operations, properties, and facilities as
3		may be necessary or convenient to carry out the purposes
4		of this Act, subject to the provisions of the Illinois
5		Administrative Procedure Act and Sections 1-22 and 1-35 of
6		this Act.
7		(24) To establish and collect charges and fees as
8		described in this Act.
9		(25) To conduct competitive gasification feedstock
10		procurement processes to procure the feedstocks for the
11		clean coal SNG brownfield facility in accordance with the
12		requirements of Section 1-78 of this Act.
13		(26) To review, revise, and approve sourcing
14		agreements and mediate and resolve disputes between gas
15		utilities and the clean coal SNG brownfield facility
16		pursuant to subsection (h-1) of Section 9-220 of the
17		Public Utilities Act.
18		(27) To request, review and accept proposals, execute
19		contracts, purchase renewable energy credits and otherwise
20		dedicate funds from the Illinois Power Agency Renewable
21		Energy Resources Fund to create and carry out the
22		objectives of the Illinois Solar for All Program in
23		accordance with Section 1-56 of this Act.
24		(28) To ensure Illinois residents and business benefit
25		from programs administered by the Agency and are properly
26		protected from any deceptive or misleading marketing

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1		practices by participants in the Agency's programs and
2		procurements.
3		(c) In conducting the procurement of electricity or other
4		products, beginning January 1, 2022, the Agency shall not
5		procure any products or services from persons or organizations
6		that are in violation of the Displaced Energy Workers Bill of
7		Rights, as provided under the Energy Community Reinvestment
8		Act at the time of the procurement event or fail to comply the
9		labor standards established in subparagraph (Q) of paragraph
10		(1) of subsection (c) of Section 1-75.
11		(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
12		(20 ILCS 3855/1-56)
13		Sec. 1-56. Illinois Power Agency Renewable Energy
14		Resources Fund; Illinois Solar for All Program.
15		(a) The Illinois Power Agency Renewable Energy Resources
16		Fund is created as a special fund in the State treasury.
17		(b) The Illinois Power Agency Renewable Energy Resources
18		Fund shall be administered by the Agency as described in this
19		subsection (b), provided that the changes to this subsection
20		(b) made by Public Act 99-906 shall not interfere with
21		existing contracts under this Section.
22		(1) The Illinois Power Agency Renewable Energy
23		Resources Fund shall be used to purchase renewable energy
24		credits according to any approved procurement plan
25		developed by the Agency prior to June 1, 2017.

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1		(2) The Illinois Power Agency Renewable Energy
2		Resources Fund shall also be used to create the Illinois
3		Solar for All Program, which provides incentives for
4		low-income distributed generation and community solar
5		projects, and other associated approved expenditures. The
6		objectives of the Illinois Solar for All Program are to
7		bring photovoltaics to low-income communities in this
8		State in a manner that maximizes the development of new
9		photovoltaic generating facilities, to create a long-term,
10		low-income solar marketplace throughout this State, to
11		integrate, through interaction with stakeholders, with
12		existing energy efficiency initiatives, and to minimize
13		administrative costs. The Illinois Solar for All Program
14		shall be implemented in a manner that seeks to minimize
15		administrative costs, and maximize efficiencies and
16		synergies available through coordination with similar
17		initiatives, including the Adjustable Block program
18		described in subparagraphs (K) through (M) of paragraph
19		(1) of subsection (c) of Section 1-75, energy efficiency
20		programs, job training programs, and community action
21		agencies, and agencies that administer the Low-Income Home
22		Energy Assistance Program. The Agency shall strive to
23		ensure that renewable energy credits procured through the
24		Illinois Solar for All Program and each of its subprograms
25		are purchased from projects across the breadth of
26		low-income and environmental justice communities in

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1		Illinois, including both urban and rural communities, are
2		not concentrated in a few communities, and do not exclude
3		particular low-income or environmental justice
4		communities. The Agency shall include a description of its
5		proposed approach to the design, administration,
6		implementation and evaluation of the Illinois Solar for
7		All Program, as part of the long-term renewable resources
8		procurement plan authorized by subsection (c) of Section
9		1-75 of this Act, and the program shall be designed to grow
10		the low-income solar market. The Agency or utility, as
11		applicable, shall purchase renewable energy credits from
12		the (i) photovoltaic distributed renewable energy
13		generation projects and (ii) community solar projects that
14		are procured under procurement processes authorized by the
15		long-term renewable resources procurement plans approved
16		by the Commission.
17		The Illinois Solar for All Program shall include the
18		program offerings described in subparagraphs (A) through
19		(E) of this paragraph (2), which the Agency shall
20		implement through contracts with third-party providers
21		and, subject to appropriation, pay the approximate amounts
22		identified using monies available in the Illinois Power
23		Agency Renewable Energy Resources Fund. Each contract that
24		provides for the installation of solar facilities shall
25		provide that the solar facilities will produce energy and
26		economic benefits, at a level determined by the Agency to

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1		be reasonable, for the participating low-income customers.
2		The monies available in the Illinois Power Agency
3		Renewable Energy Resources Fund and not otherwise
4		committed to contracts executed under subsection (i) of
5		this Section, as well as, in the case of the programs
6		described under subparagraphs (A) through (E) of this
7		paragraph (2), funding authorized pursuant to subparagraph
8		(O) of paragraph (1) of subsection (c) of Section 1-75 of
9		this Act, shall initially be allocated among the programs
10		described in this paragraph (2), as follows: 35% of these
11		funds shall be allocated to programs described in
12		subparagraphs (A) and (E) of this paragraph (2), 40% of
13		these funds shall be allocated to programs described in
14		subparagraph (B) of this paragraph (2), and 25% of these
15		funds shall be allocated to programs described in
16		subparagraph (C) of this paragraph (2). The allocation of
17		funds among subparagraphs (A), (B), (C), and (E) of this
18		paragraph (2) may be changed if the Agency, after
19		receiving input through a stakeholder process, determines
20		incentives in subparagraph subparagraphs (A), (B), (C), or
21		(E) of this paragraph (2) have not been adequately
22		subscribed to fully utilize available Illinois Solar for
23		All Program funds.
24		Contracts that will be paid with funds in the Illinois
25		Power Agency Renewable Energy Resources Fund shall be
26		executed by the Agency. Contracts that will be paid with

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1		funds collected by an electric utility shall be executed
2		by the electric utility.
3		Contracts under the Illinois Solar for All Program
4		shall include an approach, as set forth in the long-term
5		renewable resources procurement plans, to ensure the
6		wholesale market value of the energy is credited to
7		participating low-income customers or organizations and to
8		ensure tangible economic benefits flow directly to program
9		participants, except in the case of low-income
10		multi-family housing where the low-income customer does
11		not directly pay for energy. Priority shall be given to
12		projects that demonstrate meaningful involvement of
13		low-income community members in designing the initial
14		proposals. Acceptable proposals to implement projects must
15		demonstrate the applicant's ability to conduct initial
16		community outreach, education, and recruitment of
17		low-income participants in the community. Projects
18		submitted by approved vendors must either comply with the
19		minimum equity standard set forth in subsection (c-10) of
20		Section 1-75 of this Act or must include job training
21		opportunities if available, with the specific level of
22		trainee usage to be determined through the Agency's
23		long-term renewable resources procurement plan, and the
24		Illinois Solar for All Program Administrator shall
25		coordinate with the job training programs described in
26		paragraph (1) of subsection (a) of Section 16-108.12 of

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1		the Public Utilities Act and in the Energy Transition Act.
2		The Agency shall make every effort to ensure that
3		small and emerging businesses, particularly those located
4		in low-income and environmental justice communities, are
5		able to participate in the Illinois Solar for All Program.
6		These efforts may include, but shall not be limited to,
7		proactive support from the program administrator,
8		different or preferred access to subprograms and
9		administrator-identified customers or grassroots
10		education provider-identified customers, and different
11		incentive levels. The Agency shall report on progress and
12		barriers to participation of small and emerging businesses
13		in the Illinois Solar for All Program at least once a year.
14		The report shall be made available on the Agency's website
15		and, in years when the Agency is updating its long-term
16		renewable resources procurement plan, included in that
17		Plan.
18		(A) Low-income single-family and small multifamily
19		solar incentive. This program will provide incentives
20		to low-income customers, either directly or through
21		solar providers, to increase the participation of
22		low-income households in photovoltaic on-site
23		distributed generation at residential buildings
24		containing one to 4 units. Companies participating in
25		this program that install solar panels shall commit to
26		meeting a minimum equity standard or hiring job

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1		trainees for a portion of their low-income
2		installations, and an administrator shall facilitate
3		partnering the companies that install solar panels
4		with entities that provide solar panel installation
5		job training. It is a goal of this program that a
6		minimum of 25% of the incentives for this program be
7		allocated to projects located within environmental
8		justice communities. Contracts entered into under this
9		paragraph may be entered into with an entity that will
10		develop and administer the program and shall also
11		include contracts for renewable energy credits from
12		the photovoltaic distributed generation that is the
13		subject of the program, as set forth in the long-term
14		renewable resources procurement plan. Additionally:
15		(i) The Agency shall reserve a portion of this
16		program for projects that promote energy
17		sovereignty through ownership of projects by
18		low-income households, not-for-profit
19		organizations providing services to low-income
20		households, affordable housing owners, community
21		cooperatives, or community-based limited liability
22		companies providing services to low-income
23		households. Projects that feature energy ownership
24		should ensure that local people have control of
25		the project and reap benefits from the project
26		over and above energy bill savings. The Agency may

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1		consider the inclusion of projects that promote
2		ownership over time or that involve partial
3		project ownership by communities, as promoting
4		energy sovereignty. Incentives for projects that
5		promote energy sovereignty may be higher than
6		incentives for equivalent projects that do not
7		promote energy sovereignty under this same
8		program.
9		(ii) Through its long-term renewable resources
10		procurement plan, the Agency shall consider
11		additional program and contract requirements to
12		ensure faithful compliance by applicants
13		benefiting from preferences for projects
14		designated to promote energy sovereignty. The
15		Agency shall make every effort to enable solar
16		providers already participating in the Adjustable
17		Block program Program under subparagraph (K) of
18		paragraph (1) of subsection (c) of Section 1-75 of
19		this Act, and particularly solar providers
20		developing projects under item (i) of subparagraph
21		(K) of paragraph (1) of subsection (c) of Section
22		1-75 of this Act to easily participate in the
23		Low-Income Distributed Generation Incentive
24		program described under this subparagraph (A), and
25		vice versa. This effort may include, but shall not
26		be limited to, utilizing similar or the same

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1		application systems and processes, utilizing
2		similar or the same forms and formats of
3		communication, and providing active outreach to
4		companies participating in one program but not the
5		other. The Agency shall report on efforts made to
6		encourage this cross-participation in its
7		long-term renewable resources procurement plan.
8		(iii) To maximize equitable participation in
9		this program and overcome challenges facing the
10		development of residential solar projects, the
11		Agency may propose a payment structure for
12		contracts executed pursuant to this subparagraph
13		(A) under which applicant firms are advanced
14		capital that is disbursed after contract execution
15		but before the contracted project's energization,
16		upon a demonstration of qualification or need
17		under criteria established by the Agency that are
18		focused on supporting the small and emerging
19		businesses and the businesses that most acutely
20		face barriers to capital access, which severely
21		limits the businesses' participation in the
22		program described in this subparagraph (A). The
23		amount or percentage of capital advanced before
24		project energization shall be designed to overcome
25		the barriers in access to capital that are faced
26		by an applicant. The amount or percentage of

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1		advanced capital may vary under this subparagraph
2		(A) by an applicant's demonstration of need, with
3		such levels to be established through the
4		Long-Term Renewable Resources Procurement Plan and
5		any application requirements or evaluation
6		criteria developed under that Plan.
7		(B) Low-Income Community Solar Project Initiative.
8		Incentives shall be offered to low-income customers,
9		either directly or through developers, to increase the
10		participation of low-income subscribers of community
11		solar projects. The developer of each project shall
12		identify its partnership with community stakeholders
13		regarding the location, development, and participation
14		in the project, provided that nothing shall preclude a
15		project from including an anchor tenant that does not
16		qualify as low-income. Companies participating in this
17		program that develop or install solar projects shall
18		commit to meeting a minimum equity standard or to
19		hiring job trainees for a portion of their low-income
20		installations, and an administrator shall facilitate
21		partnering the companies that install solar projects
22		with entities that provide solar installation and
23		related job training. It is a goal of this program that
24		a minimum of 25% of the incentives for this program be
25		allocated to community photovoltaic projects in
26		environmental justice communities. The Agency shall

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1		reserve a portion of this program for projects that
2		promote energy sovereignty through ownership of
3		projects by low-income households, not-for-profit
4		organizations providing services to low-income
5		households, affordable housing owners, or
6		community-based limited liability companies providing
7		services to low-income households. Projects that
8		feature energy ownership should ensure that local
9		people have control of the project and reap benefits
10		from the project over and above energy bill savings.
11		The Agency may consider the inclusion of projects that
12		promote ownership over time or that involve partial
13		project ownership by communities, as promoting energy
14		sovereignty. Incentives for projects that promote
15		energy sovereignty may be higher than incentives for
16		equivalent projects that do not promote energy
17		sovereignty under this same program. Contracts entered
18		into under this paragraph may be entered into with
19		developers and shall also include contracts for
20		renewable energy credits related to the program.
21		(C) Incentives for non-profits and public
22		facilities. Under this program funds shall be used to
23		support on-site photovoltaic distributed renewable
24		energy generation devices to serve the load associated
25		with not-for-profit customers and to support
26		photovoltaic distributed renewable energy generation

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1		that uses photovoltaic technology to serve the load
2		associated with public sector customers taking service
3		at public buildings. Master-metered multifamily
4		buildings that primarily house income-eligible
5		residents may qualify under this subparagraph (C).
6		Nonprofits and public facilities that can demonstrate
7		that the nonprofit or public facility serves
8		income-qualified or environmental justice communities
9		may potentially qualify for the program, regardless of
10		physical location. Qualification may be determined
11		using the same procedures applied to critical service
12		provider requests for the purpose of establishing
13		project eligibility in areas that are not designated
14		as income-eligible or environmental justice
15		communities. Companies participating in this program
16		that develop or install solar projects shall commit to
17		meeting a minimum equity standard or to hiring job
18		trainees for a portion of their low-income
19		installations, and an administrator shall facilitate
20		partnering the companies that install solar projects
21		with entities that provide solar installation and
22		related job training. Through its long-term renewable
23		resources procurement plan, the Agency shall consider
24		additional program and contract requirements to ensure
25		faithful compliance by applicants benefiting from
26		preferences for projects designated to promote energy

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1		sovereignty. It is a goal of this program that at least
2		25% of the incentives for this program be allocated to
3		projects located in environmental justice communities.
4		Contracts entered into under this paragraph may be
5		entered into with an entity that will develop and
6		administer the program or with developers and shall
7		also include contracts for renewable energy credits
8		related to the program.
9		(D) (Blank).
10		(E) Low-income large multifamily solar incentive.
11		This program shall provide incentives to low-income
12		customers, either directly or through solar providers,
13		to increase the participation of low-income households
14		in photovoltaic on-site distributed generation at
15		residential buildings with 5 or more units. Companies
16		participating in this program that develop or install
17		solar projects shall commit to meeting a minimum
18		equity standard or to hiring job trainees for a
19		portion of their low-income installations, and an
20		administrator shall facilitate partnering the
21		companies that install solar projects with entities
22		that provide solar installation and related job
23		training. It is a goal of this program that a minimum
24		of 25% of the incentives for this program be allocated
25		to projects located within environmental justice
26		communities. The Agency shall reserve a portion of

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1		this program for projects that promote energy
2		sovereignty through ownership of projects by
3		low-income households, not-for-profit organizations
4		providing services to low-income households,
5		affordable housing owners, or community-based limited
6		liability companies providing services to low-income
7		households. Projects that feature energy ownership
8		should ensure that local people have control of the
9		project and reap benefits from the project over and
10		above energy bill savings. The Agency may consider the
11		inclusion of projects that promote ownership over time
12		or that involve partial project ownership by
13		communities, as promoting energy sovereignty.
14		Incentives for projects that promote energy
15		sovereignty may be higher than incentives for
16		equivalent projects that do not promote energy
17		sovereignty under this same program.
18		The requirement that a qualified person, as defined in
19		paragraph (1) of subsection (i) of this Section, install
20		photovoltaic devices does not apply to the Illinois Solar
21		for All Program described in this subsection (b).
22		In addition to the programs outlined in paragraphs (A)
23		through (E), the Agency and other parties may propose
24		additional programs through the long-term renewable
25		resources procurement plan Long-Term Renewable Resources
26		Procurement Plan developed and approved under paragraph

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1		(5) of subsection (b) of Section 16-111.5 of the Public
2		Utilities Act. Additional programs may target market
3		segments not specified above and may also include
4		incentives targeted to increase the uptake of
5		nonphotovoltaic technologies by low-income customers,
6		including energy storage paired with photovoltaics, if the
7		Commission determines that the Illinois Solar for All
8		Program would provide greater benefits to the public
9		health and well-being of low-income residents through also
10		supporting that additional program versus supporting
11		programs already authorized.
12		(3) Costs associated with the Illinois Solar for All
13		Program and its components described in paragraph (2) of
14		this subsection (b), including, but not limited to, costs
15		associated with procuring experts, consultants, and the
16		program administrator referenced in this subsection (b)
17		and related incremental costs, costs related to income
18		verification and facilitating customer participation in
19		the program through referrals and other methods, costs
20		related to obtaining feedback on the program from parties
21		that do not have a financial interest, and costs related
22		to the evaluation of the Illinois Solar for All Program,
23		may be paid for using monies in the Illinois Power Agency
24		Renewable Energy Resources Fund, and funds allocated
25		pursuant to subparagraph (O) of paragraph (1) of
26		subsection (c) of Section 1-75, but the Agency or program

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1		administrator shall strive to minimize costs in the
2		implementation of the program. The Agency or contracting
3		electric utility shall purchase renewable energy credits
4		from generation that is the subject of a contract under
5		subparagraphs (A) through (E) of paragraph (2) of this
6		subsection (b), and may pay for such renewable energy
7		credits through an upfront payment per installed kilowatt
8		of nameplate capacity paid once the device is
9		interconnected at the distribution system level of the
10		interconnecting utility and verified as energized. Unless
11		otherwise provided in the Agency's long-term renewable
12		resources procurement plan, payments Payments for
13		renewable energy credits shall be in exchange for all
14		renewable energy credits generated by the system during
15		the first 15 years of operation and shall be structured to
16		overcome barriers to participation in the solar market by
17		the low-income community. The incentives provided for in
18		this Section may be implemented through the pricing of
19		renewable energy credits where the prices paid for the
20		credits are higher than the prices from programs offered
21		under subsection (c) of Section 1-75 of this Act to
22		account for the additional capital necessary to
23		successfully access targeted market segments. The Agency
24		or contracting electric utility shall retire any renewable
25		energy credits purchased under this program and the
26		credits shall count toward the obligation under subsection

SB0025 Enrolled - 171 - LRB104 07069 BAB 17106 b
1		(c) of Section 1-75 of this Act for the electric utility to
2		which the project is interconnected, if applicable.
3		The Agency shall direct that up to 5% of the funds
4		available under the Illinois Solar for All Program to
5		community-based groups and other qualifying organizations
6		to assist in community-driven education efforts related to
7		the Illinois Solar for All Program, including general
8		energy education, job training program outreach efforts,
9		and other activities deemed to be qualified by the Agency.
10		Grassroots education funding shall not be used to support
11		the marketing by solar project development firms and
12		organizations, unless such education provides equal
13		opportunities for all applicable firms and organizations.
14		The Agency may direct up to 25% of the funds currently
15		allocated to subparagraphs (A), (C), and (E) of paragraph
16		(2) toward the Illinois Storage for All Program, which
17		provides incentives through grants, rebates, or other
18		incentives to encourage development of energy storage
19		colocated with photovoltaic distributed renewable energy
20		generation devices developed through the Illinois Solar
21		for All Program. Any unused Storage for All funds during a
22		program year may be reallocated to other Solar for All
23		Program projects that are waitlisted or otherwise not
24		selected due to funding limitation per the Agency's
25		defined process. The Illinois Storage for All Program
26		shall be available to current and future participants of

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1		the low-income single-family and multifamily subprogram
2		described in subparagraphs (A) and (E) of paragraph (2),
3		and the subprogram for nonprofit and public facilities
4		described in subparagraph (C) of paragraph (2). If
5		developed, the Illinois Storage for All Program may be
6		designed to support community energy resilience, disaster
7		preparedness, and energy bill reductions, particularly for
8		residents of low-income and environmental justice
9		communities. The Agency may propose the funding amount,
10		structure, and details of the Illinois Storage for All
11		Program in the Agency's long-term renewable resources
12		procurement plan described in subsection (c) of Section
13		1-75 of this Act and Section 16-111.5 of the Public
14		Utilities Act, or through its energy storage resources
15		procurement plan described in subsection (d-20) of Section
16		1-75 of this Act. As part of the development of its initial
17		energy storage resources procurement plan, the Agency
18		shall engage stakeholders in the development of the
19		Illinois Storage for All Program, including, but not
20		limited to, members of the Illinois Commission on
21		Environmental Justice described in Section 10 of the
22		Environmental Justice Act, representatives of approved
23		vendors participating in the Illinois Solar for All
24		Program, representatives of community-based
25		organizations, and members of the Illinois Solar for All
26		Stakeholder Advisory Group. The stakeholder process shall

SB0025 Enrolled - 173 - LRB104 07069 BAB 17106 b
1		include, but not be limited to, an exploration of how to
2		ensure that the distributed storage will be accessible to
3		income-qualified households with zero upfront costs and in
4		coordination with job training programs, as well as how
5		the program may be supported by other programs or
6		initiatives to maximize storage benefits and limit
7		double-counting of incentives.
8		(4) The Agency shall, consistent with the requirements
9		of this subsection (b), propose the Illinois Solar for All
10		Program terms, conditions, and requirements, including the
11		prices to be paid for renewable energy credits, and which
12		prices may be determined through a formula, through the
13		development, review, and approval of the Agency's
14		long-term renewable resources procurement plan described
15		in subsection (c) of Section 1-75 of this Act and Section
16		16-111.5 of the Public Utilities Act. In the course of the
17		Commission proceeding initiated to review and approve the
18		plan, including the Illinois Solar for All Program
19		proposed by the Agency, a party may propose an additional
20		low-income solar or solar incentive program, or
21		modifications to the programs proposed by the Agency, and
22		the Commission may approve an additional program, or
23		modifications to the Agency's proposed program, if the
24		additional or modified program more effectively maximizes
25		the benefits to low-income customers after taking into
26		account all relevant factors, including, but not limited

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1		to, the extent to which a competitive market for
2		low-income solar has developed. Following the Commission's
3		approval of the Illinois Solar for All Program, the Agency
4		or a party may propose adjustments to the program terms,
5		conditions, and requirements, including the price offered
6		to new systems, to ensure the long-term viability and
7		success of the program. The Commission shall review and
8		approve any modifications to the program through the plan
9		revision process described in Section 16-111.5 of the
10		Public Utilities Act.
11		(5) The Agency shall issue a request for
12		qualifications for a third-party program administrator or
13		administrators to administer all or a portion of the
14		Illinois Solar for All Program. The third-party program
15		administrator shall be chosen through a competitive bid
16		process based on selection criteria and requirements
17		developed by the Agency, including, but not limited to,
18		experience in administering low-income energy programs and
19		overseeing statewide clean energy or energy efficiency
20		services. If the Agency retains a program administrator or
21		administrators to implement all or a portion of the
22		Illinois Solar for All Program, each administrator shall
23		periodically submit reports to the Agency and Commission
24		for each program that it administers, at appropriate
25		intervals to be identified by the Agency in its long-term
26		renewable resources procurement plan, subject to

SB0025 Enrolled - 175 - LRB104 07069 BAB 17106 b
1		Commission approval, provided that the reporting interval
2		is at least an annual period quarterly. The third-party
3		program administrator may be, but need not be, the same
4		administrator as for the Adjustable Block program
5		described in subparagraphs (K) through (M) of paragraph
6		(1) of subsection (c) of Section 1-75. The Agency, through
7		its long-term renewable resources procurement plan
8		approval process, shall also determine if individual
9		subprograms of the Illinois Solar for All Program are
10		better served by a different or separate Program
11		Administrator.
12		The third-party administrator's responsibilities
13		shall also include facilitating placement for graduates of
14		Illinois-based renewable energy-specific job training
15		programs, including the Clean Jobs Workforce Network
16		Program and the Illinois Climate Works Preapprenticeship
17		Program administered by the Department of Commerce and
18		Economic Opportunity and programs administered under
19		Section 16-108.12 of the Public Utilities Act. To increase
20		the uptake of trainees by participating firms, the
21		administrator shall also develop a web-based clearinghouse
22		for information available to both job training program
23		graduates and firms participating, directly or indirectly,
24		in Illinois solar incentive programs. The program
25		administrator shall also coordinate its activities with
26		entities implementing electric and natural gas

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1		income-qualified energy efficiency programs, including
2		customer referrals to and from such programs, and connect
3		prospective low-income solar customers with any existing
4		deferred maintenance programs where applicable.
5		(6) The long-term renewable resources procurement plan
6		shall also provide for an independent evaluation of the
7		Illinois Solar for All Program. At least every 5 2 years,
8		the Agency shall select an independent evaluator to review
9		and report on the Illinois Solar for All Program and the
10		performance of the third-party program administrator of
11		the Illinois Solar for All Program. The evaluation shall
12		be based on objective criteria developed through a public
13		stakeholder process. The process shall include feedback
14		and participation from Illinois Solar for All Program
15		stakeholders, including participants and organizations in
16		environmental justice and historically underserved
17		communities. The report shall include a summary of the
18		evaluation of the Illinois Solar for All Program based on
19		the stakeholder developed objective criteria. The report
20		shall include the number of projects installed; the total
21		installed capacity in kilowatts; the average cost per
22		kilowatt of installed capacity to the extent reasonably
23		obtainable by the Agency; the number of jobs or job
24		opportunities created; economic, social, and environmental
25		benefits created; and the total administrative costs
26		expended by the Agency and program administrator to

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1		implement and evaluate the program. The report shall be
2		prepared at least every 2 years and shall be delivered to
3		the Commission and posted on the Agency's website, and
4		shall be used, as needed, to revise the Illinois Solar for
5		All Program. The Commission shall also consider the
6		results of the evaluation as part of its review of the
7		long-term renewable resources procurement plan under
8		subsection (c) of Section 1-75 of this Act.
9		(7) If additional funding for the programs described
10		in this subsection (b) is available under subsection (k)
11		of Section 16-108 of the Public Utilities Act, then the
12		Agency shall submit a procurement plan to the Commission
13		no later than September 1, 2018, that proposes how the
14		Agency will procure programs on behalf of the applicable
15		utility. After notice and hearing, the Commission shall
16		approve, or approve with modification, the plan no later
17		than November 1, 2018.
18		(8) As part of the development and update of the
19		long-term renewable resources procurement plan authorized
20		by subsection (c) of Section 1-75 of this Act, the Agency
21		shall plan for: (A) actions to refer customers from the
22		Illinois Solar for All Program to electric and natural gas
23		income-qualified energy efficiency programs, and vice
24		versa, with the goal of increasing participation in both
25		of these programs; (B) effective procedures for data
26		sharing, as needed, to effectuate referrals between the

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1		Illinois Solar for All Program and both electric and
2		natural gas income-qualified energy efficiency programs,
3		including sharing customer information directly with the
4		utilities, as needed and appropriate; and (C) efforts to
5		identify any existing deferred maintenance programs for
6		which prospective Solar for All Program customers may be
7		eligible and connect prospective customers for whom
8		deferred maintenance is or may be a barrier to solar
9		installation to those programs.
10		Income verification for participation in the Illinois
11		Solar for All subprograms described in subparagraphs (A) and
12		(C) of paragraph (2) may include pathways for verification
13		that rely on self-attestation by the applicant if the
14		applicant's residence is located within a low-income or
15		environmental justice community as defined in this subsection
16		(b). The Agency shall proactively explore approaches that make
17		the income verification process less burdensome for residents
18		of low-income or environmental justice communities, as defined
19		in this subsection (b).
20		As used in this subsection (b), "low-income households"
21		means persons and families whose income does not exceed 80% of
22		area median income, adjusted for family size and revised every
23		year.
24		For the purposes of this subsection (b), the Agency shall
25		define "environmental justice community" based on the
26		methodologies and findings established by the Agency and the

SB0025 Enrolled - 179 - LRB104 07069 BAB 17106 b
1		Administrator for the Illinois Solar for All Program in its
2		initial long-term renewable resources procurement plan and as
3		updated by the Agency and the Administrator for the Illinois
4		Solar for All Program as part of the long-term renewable
5		resources procurement plan update.
6		(b-5) After the receipt of all payments required by
7		Section 16-115D of the Public Utilities Act, no additional
8		funds shall be deposited into the Illinois Power Agency
9		Renewable Energy Resources Fund unless directed by order of
10		the Commission.
11		(b-10) After the receipt of all payments required by
12		Section 16-115D of the Public Utilities Act and payment in
13		full of all contracts executed by the Agency under subsections
14		(b) and (i) of this Section, if the balance of the Illinois
15		Power Agency Renewable Energy Resources Fund is under $5,000,
16		then the Fund shall be inoperative and any remaining funds and
17		any funds submitted to the Fund after that date, shall be
18		transferred to the Supplemental Low-Income Energy Assistance
19		Fund for use in the Low-Income Home Energy Assistance Program,
20		as authorized by the Energy Assistance Act.
21		(b-15) The prevailing wage requirements set forth in the
22		Prevailing Wage Act apply to each project that is undertaken
23		pursuant to one or more of the programs of incentives and
24		initiatives described in subsection (b) of this Section and
25		for which a project application is submitted to the program
26		after June 30, 2023 (the effective date of Public Act 103-188)

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1		this amendatory Act of the 103rd General Assembly, except (i)
2		projects that serve single-family or multi-family residential
3		buildings and (ii) projects with an aggregate capacity of less
4		than 100 kilowatts that serve houses of worship. The Agency
5		shall require verification that all construction performed on
6		a project by the renewable energy credit delivery contract
7		holder, its contractors, or its subcontractors relating to the
8		construction of the facility is performed by workers receiving
9		an amount for that work that is greater than or equal to the
10		general prevailing rate of wages as that term is defined in the
11		Prevailing Wage Act, and the Agency may adjust renewable
12		energy credit prices to account for increased labor costs.
13		In this subsection (b-15), "house of worship" has the
14		meaning given in subparagraph (Q) of paragraph (1) of
15		subsection (c) of Section 1-75.
16		(c) (Blank).
17		(d) (Blank).
18		(e) All renewable energy credits procured using monies
19		from the Illinois Power Agency Renewable Energy Resources Fund
20		shall be permanently retired.
21		(f) The selection of one or more third-party program
22		managers or administrators, the selection of the independent
23		evaluator, and the procurement processes described in this
24		Section are exempt from the requirements of the Illinois
25		Procurement Code, under Section 20-10 of that Code.
26		(g) All disbursements from the Illinois Power Agency

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1		Renewable Energy Resources Fund shall be made only upon
2		warrants of the Comptroller drawn upon the Treasurer as
3		custodian of the Fund upon vouchers signed by the Director or
4		by the person or persons designated by the Director for that
5		purpose. The Comptroller is authorized to draw the warrant
6		upon vouchers so signed. The Treasurer shall accept all
7		warrants so signed and shall be released from liability for
8		all payments made on those warrants.
9		(h) The Illinois Power Agency Renewable Energy Resources
10		Fund shall not be subject to sweeps, administrative charges,
11		or chargebacks, including, but not limited to, those
12		authorized under Section 8h of the State Finance Act, that
13		would in any way result in the transfer of any funds from this
14		Fund to any other fund of this State or in having any such
15		funds utilized for any purpose other than the express purposes
16		set forth in this Section.
17		(h-5) The Agency may assess fees to each bidder to recover
18		the costs incurred in connection with a procurement process
19		held under this Section. Fees collected from bidders shall be
20		deposited into the Illinois Power Agency Renewable Energy
21		Resources Fund.
22		(i) Supplemental procurement process.
23		(1) Within 90 days after June 30, 2014 (the effective
24		date of Public Act 98-672), the Agency shall develop a
25		one-time supplemental procurement plan limited to the
26		procurement of renewable energy credits, if available,

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1		from new or existing photovoltaics, including, but not
2		limited to, distributed photovoltaic generation. Nothing
3		in this subsection (i) requires procurement of wind
4		generation through the supplemental procurement.
5		Renewable energy credits procured from new
6		photovoltaics, including, but not limited to, distributed
7		photovoltaic generation, under this subsection (i) must be
8		procured from devices installed by a qualified person. In
9		its supplemental procurement plan, the Agency shall
10		establish contractually enforceable mechanisms for
11		ensuring that the installation of new photovoltaics is
12		performed by a qualified person.
13		For the purposes of this paragraph (1), "qualified
14		person" means a person who performs installations of
15		photovoltaics, including, but not limited to, distributed
16		photovoltaic generation, and who: (A) has completed an
17		apprenticeship as a journeyman electrician from a United
18		States Department of Labor registered electrical
19		apprenticeship and training program and received a
20		certification of satisfactory completion; or (B) does not
21		currently meet the criteria under clause (A) of this
22		paragraph (1), but is enrolled in a United States
23		Department of Labor registered electrical apprenticeship
24		program, provided that the person is directly supervised
25		by a person who meets the criteria under clause (A) of this
26		paragraph (1); or (C) has obtained one of the following

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1		credentials in addition to attesting to satisfactory
2		completion of at least 5 years or 8,000 hours of
3		documented hands-on electrical experience: (i) a North
4		American Board of Certified Energy Practitioners (NABCEP)
5		Installer Certificate for Solar PV; (ii) an Underwriters
6		Laboratories (UL) PV Systems Installer Certificate; (iii)
7		an Electronics Technicians Association, International
8		(ETAI) Level 3 PV Installer Certificate; or (iv) an
9		Associate in Applied Science degree from an Illinois
10		Community College Board approved community college program
11		in renewable energy or a distributed generation
12		technology.
13		For the purposes of this paragraph (1), "directly
14		supervised" means that there is a qualified person who
15		meets the qualifications under clause (A) of this
16		paragraph (1) and who is available for supervision and
17		consultation regarding the work performed by persons under
18		clause (B) of this paragraph (1), including a final
19		inspection of the installation work that has been directly
20		supervised to ensure safety and conformity with applicable
21		codes.
22		For the purposes of this paragraph (1), "install"
23		means the major activities and actions required to
24		connect, in accordance with applicable building and
25		electrical codes, the conductors, connectors, and all
26		associated fittings, devices, power outlets, or

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1		apparatuses mounted at the premises that are directly
2		involved in delivering energy to the premises' electrical
3		wiring from the photovoltaics, including, but not limited
4		to, to distributed photovoltaic generation.
5		The renewable energy credits procured pursuant to the
6		supplemental procurement plan shall be procured using up
7		to $30,000,000 from the Illinois Power Agency Renewable
8		Energy Resources Fund. The Agency shall not plan to use
9		funds from the Illinois Power Agency Renewable Energy
10		Resources Fund in excess of the monies on deposit in such
11		fund or projected to be deposited into such fund. The
12		supplemental procurement plan shall ensure adequate,
13		reliable, affordable, efficient, and environmentally
14		sustainable renewable energy resources (including credits)
15		at the lowest total cost over time, taking into account
16		any benefits of price stability.
17		To the extent available, 50% of the renewable energy
18		credits procured from distributed renewable energy
19		generation shall come from devices of less than 25
20		kilowatts in nameplate capacity. Procurement of renewable
21		energy credits from distributed renewable energy
22		generation devices shall be done through multi-year
23		contracts of no less than 5 years. The Agency shall create
24		credit requirements for counterparties. In order to
25		minimize the administrative burden on contracting
26		entities, the Agency shall solicit the use of third

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1		parties to aggregate distributed renewable energy. These
2		third parties shall enter into and administer contracts
3		with individual distributed renewable energy generation
4		device owners. An individual distributed renewable energy
5		generation device owner shall have the ability to measure
6		the output of his or her distributed renewable energy
7		generation device.
8		In developing the supplemental procurement plan, the
9		Agency shall hold at least one workshop open to the public
10		within 90 days after June 30, 2014 (the effective date of
11		Public Act 98-672) and shall consider any comments made by
12		stakeholders or the public. Upon development of the
13		supplemental procurement plan within this 90-day period,
14		copies of the supplemental procurement plan shall be
15		posted and made publicly available on the Agency's and
16		Commission's websites. All interested parties shall have
17		14 days following the date of posting to provide comment
18		to the Agency on the supplemental procurement plan. All
19		comments submitted to the Agency shall be specific,
20		supported by data or other detailed analyses, and, if
21		objecting to all or a portion of the supplemental
22		procurement plan, accompanied by specific alternative
23		wording or proposals. All comments shall be posted on the
24		Agency's and Commission's websites. Within 14 days
25		following the end of the 14-day review period, the Agency
26		shall revise the supplemental procurement plan as

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1		necessary based on the comments received and file its
2		revised supplemental procurement plan with the Commission
3		for approval.
4		(2) Within 5 days after the filing of the supplemental
5		procurement plan at the Commission, any person objecting
6		to the supplemental procurement plan shall file an
7		objection with the Commission. Within 10 days after the
8		filing, the Commission shall determine whether a hearing
9		is necessary. The Commission shall enter its order
10		confirming or modifying the supplemental procurement plan
11		within 90 days after the filing of the supplemental
12		procurement plan by the Agency.
13		(3) The Commission shall approve the supplemental
14		procurement plan of renewable energy credits to be
15		procured from new or existing photovoltaics, including,
16		but not limited to, distributed photovoltaic generation,
17		if the Commission determines that it will ensure adequate,
18		reliable, affordable, efficient, and environmentally
19		sustainable electric service in the form of renewable
20		energy credits at the lowest total cost over time, taking
21		into account any benefits of price stability.
22		(4) The supplemental procurement process under this
23		subsection (i) shall include each of the following
24		components:
25		(A) Procurement administrator. The Agency may
26		retain a procurement administrator in the manner set

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1		forth in item (2) of subsection (a) of Section 1-75 of
2		this Act to conduct the supplemental procurement or
3		may elect to use the same procurement administrator
4		administering the Agency's annual procurement under
5		Section 1-75.
6		(B) Procurement monitor. The procurement monitor
7		retained by the Commission pursuant to Section
8		16-111.5 of the Public Utilities Act shall:
9		(i) monitor interactions among the procurement
10		administrator and bidders and suppliers;
11		(ii) monitor and report to the Commission on
12		the progress of the supplemental procurement
13		process;
14		(iii) provide an independent confidential
15		report to the Commission regarding the results of
16		the procurement events;
17		(iv) assess compliance with the procurement
18		plan approved by the Commission for the
19		supplemental procurement process;
20		(v) preserve the confidentiality of supplier
21		and bidding information in a manner consistent
22		with all applicable laws, rules, regulations, and
23		tariffs;
24		(vi) provide expert advice to the Commission
25		and consult with the procurement administrator
26		regarding issues related to procurement process

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1		design, rules, protocols, and policy-related
2		matters;
3		(vii) consult with the procurement
4		administrator regarding the development and use of
5		benchmark criteria, standard form contracts,
6		credit policies, and bid documents; and
7		(viii) perform, with respect to the
8		supplemental procurement process, any other
9		procurement monitor duties specifically delineated
10		within subsection (i) of this Section.
11		(C) Solicitation, prequalification, and
12		registration of bidders. The procurement administrator
13		shall disseminate information to potential bidders to
14		promote a procurement event, notify potential bidders
15		that the procurement administrator may enter into a
16		post-bid price negotiation with bidders that meet the
17		applicable benchmarks, provide supply requirements,
18		and otherwise explain the competitive procurement
19		process. In addition to such other publication as the
20		procurement administrator determines is appropriate,
21		this information shall be posted on the Agency's and
22		the Commission's websites. The procurement
23		administrator shall also administer the
24		prequalification process, including evaluation of
25		credit worthiness, compliance with procurement rules,
26		and agreement to the standard form contract developed

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1		pursuant to item (D) of this paragraph (4). The
2		procurement administrator shall then identify and
3		register bidders to participate in the procurement
4		event.
5		(D) Standard contract forms and credit terms and
6		instruments. The procurement administrator, in
7		consultation with the Agency, the Commission, and
8		other interested parties and subject to Commission
9		oversight, shall develop and provide standard contract
10		forms for the supplier contracts that meet generally
11		accepted industry practices as well as include any
12		applicable State of Illinois terms and conditions that
13		are required for contracts entered into by an agency
14		of the State of Illinois. Standard credit terms and
15		instruments that meet generally accepted industry
16		practices shall be similarly developed. Contracts for
17		new photovoltaics shall include a provision attesting
18		that the supplier will use a qualified person for the
19		installation of the device pursuant to paragraph (1)
20		of subsection (i) of this Section. The procurement
21		administrator shall make available to the Commission
22		all written comments it receives on the contract
23		forms, credit terms, or instruments. If the
24		procurement administrator cannot reach agreement with
25		the parties as to the contract terms and conditions,
26		the procurement administrator must notify the

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1		Commission of any disputed terms and the Commission
2		shall resolve the dispute. The terms of the contracts
3		shall not be subject to negotiation by winning
4		bidders, and the bidders must agree to the terms of the
5		contract in advance so that winning bids are selected
6		solely on the basis of price.
7		(E) Requests for proposals; competitive
8		procurement process. The procurement administrator
9		shall design and issue requests for proposals to
10		supply renewable energy credits in accordance with the
11		supplemental procurement plan, as approved by the
12		Commission. The requests for proposals shall set forth
13		a procedure for sealed, binding commitment bidding
14		with pay-as-bid settlement, and provision for
15		selection of bids on the basis of price, provided,
16		however, that no bid shall be accepted if it exceeds
17		the benchmark developed pursuant to item (F) of this
18		paragraph (4).
19		(F) Benchmarks. Benchmarks for each product to be
20		procured shall be developed by the procurement
21		administrator in consultation with Commission staff,
22		the Agency, and the procurement monitor for use in
23		this supplemental procurement.
24		(G) A plan for implementing contingencies in the
25		event of supplier default, Commission rejection of
26		results, or any other cause.

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1		(5) Within 2 business days after opening the sealed
2		bids, the procurement administrator shall submit a
3		confidential report to the Commission. The report shall
4		contain the results of the bidding for each of the
5		products along with the procurement administrator's
6		recommendation for the acceptance and rejection of bids
7		based on the price benchmark criteria and other factors
8		observed in the process. The procurement monitor also
9		shall submit a confidential report to the Commission
10		within 2 business days after opening the sealed bids. The
11		report shall contain the procurement monitor's assessment
12		of bidder behavior in the process as well as an assessment
13		of the procurement administrator's compliance with the
14		procurement process and rules. The Commission shall review
15		the confidential reports submitted by the procurement
16		administrator and procurement monitor and shall accept or
17		reject the recommendations of the procurement
18		administrator within 2 business days after receipt of the
19		reports.
20		(6) Within 3 business days after the Commission
21		decision approving the results of a procurement event, the
22		Agency shall enter into binding contractual arrangements
23		with the winning suppliers using the standard form
24		contracts.
25		(7) The names of the successful bidders and the
26		average of the winning bid prices for each contract type

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1		and for each contract term shall be made available to the
2		public within 2 days after the supplemental procurement
3		event. The Commission, the procurement monitor, the
4		procurement administrator, the Agency, and all
5		participants in the procurement process shall maintain the
6		confidentiality of all other supplier and bidding
7		information in a manner consistent with all applicable
8		laws, rules, regulations, and tariffs. Confidential
9		information, including the confidential reports submitted
10		by the procurement administrator and procurement monitor
11		pursuant to this Section, shall not be made publicly
12		available and shall not be discoverable by any party in
13		any proceeding, absent a compelling demonstration of need,
14		nor shall those reports be admissible in any proceeding
15		other than one for law enforcement purposes.
16		(8) The supplemental procurement provided in this
17		subsection (i) shall not be subject to the requirements
18		and limitations of subsections (c) and (d) of this
19		Section.
20		(9) Expenses incurred in connection with the
21		procurement process held pursuant to this Section,
22		including, but not limited to, the cost of developing the
23		supplemental procurement plan, the procurement
24		administrator, procurement monitor, and the cost of the
25		retirement of renewable energy credits purchased pursuant
26		to the supplemental procurement shall be paid for from the

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1		Illinois Power Agency Renewable Energy Resources Fund. The
2		Agency shall enter into an interagency agreement with the
3		Commission to reimburse the Commission for its costs
4		associated with the procurement monitor for the
5		supplemental procurement process.
6		(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23;
7		103-605, eff. 7-1-24; 103-1066, eff. 2-20-25; revised
8		6-23-25.)
9		(20 ILCS 3855/1-75)
10		Sec. 1-75. Planning and Procurement Bureau. The Planning
11		and Procurement Bureau has the following duties and
12		responsibilities:
13		(a) The Planning and Procurement Bureau shall each year,
14		beginning in 2008, develop procurement plans and conduct
15		competitive procurement processes in accordance with the
16		requirements of Section 16-111.5 of the Public Utilities Act
17		for the eligible retail customers of electric utilities that
18		on December 31, 2005 provided electric service to at least
19		100,000 customers in Illinois. Beginning with the delivery
20		year commencing on June 1, 2017, the Planning and Procurement
21		Bureau shall develop plans and processes for the procurement
22		of zero emission credits from zero emission facilities in
23		accordance with the requirements of subsection (d-5) of this
24		Section. Beginning on the effective date of this amendatory
25		Act of the 102nd General Assembly, the Planning and

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1		Procurement Bureau shall develop plans and processes for the
2		procurement of carbon mitigation credits from carbon-free
3		energy resources in accordance with the requirements of
4		subsection (d-10) of this Section. The Planning and
5		Procurement Bureau shall also develop procurement plans and
6		conduct competitive procurement processes in accordance with
7		the requirements of Section 16-111.5 of the Public Utilities
8		Act for the eligible retail customers of small
9		multi-jurisdictional electric utilities that (i) on December
10		31, 2005 served less than 100,000 customers in Illinois and
11		(ii) request a procurement plan for their Illinois
12		jurisdictional load. This Section shall not apply to a small
13		multi-jurisdictional utility until such time as a small
14		multi-jurisdictional utility requests the Agency to prepare a
15		procurement plan for their Illinois jurisdictional load. For
16		the purposes of this Section, the term "eligible retail
17		customers" has the same definition as found in Section
18		16-111.5(a) of the Public Utilities Act.
19		Beginning with the plan or plans to be implemented in the
20		2017 delivery year, the Agency shall no longer include the
21		procurement of renewable energy resources in the annual
22		procurement plans required by this subsection (a), except as
23		provided in subsection (q) of Section 16-111.5 of the Public
24		Utilities Act, and shall instead develop a long-term renewable
25		resources procurement plan in accordance with subsection (c)
26		of this Section and Section 16-111.5 of the Public Utilities

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1		Act.
2		In accordance with subsection (c-5) of this Section, the
3		Planning and Procurement Bureau shall oversee the procurement
4		by electric utilities that served more than 300,000 retail
5		customers in this State as of January 1, 2019 of renewable
6		energy credits from new utility-scale solar projects to be
7		installed, along with energy storage facilities, at or
8		adjacent to the sites of electric generating facilities that,
9		as of January 1, 2016, burned coal as their primary fuel
10		source.
11		(1) The Agency shall each year, beginning in 2008, as
12		needed, issue a request for qualifications for experts or
13		expert consulting firms to develop the procurement plans
14		in accordance with Section 16-111.5 of the Public
15		Utilities Act. In order to qualify an expert or expert
16		consulting firm must have:
17		(A) direct previous experience assembling
18		large-scale power supply plans or portfolios for
19		end-use customers;
20		(B) an advanced degree in economics, mathematics,
21		engineering, risk management, or a related area of
22		study;
23		(C) 10 years of experience in the electricity
24		sector, including managing supply risk;
25		(D) expertise in wholesale electricity market
26		rules, including those established by the Federal

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1		Energy Regulatory Commission and regional transmission
2		organizations;
3		(E) expertise in credit protocols and familiarity
4		with contract protocols;
5		(F) adequate resources to perform and fulfill the
6		required functions and responsibilities; and
7		(G) the absence of a conflict of interest and
8		inappropriate bias for or against potential bidders or
9		the affected electric utilities.
10		(2) The Agency shall each year, as needed, issue a
11		request for qualifications for a procurement administrator
12		to conduct the competitive procurement processes in
13		accordance with Section 16-111.5 of the Public Utilities
14		Act. In order to qualify an expert or expert consulting
15		firm must have:
16		(A) direct previous experience administering a
17		large-scale competitive procurement process;
18		(B) an advanced degree in economics, mathematics,
19		engineering, or a related area of study;
20		(C) 10 years of experience in the electricity
21		sector, including risk management experience;
22		(D) expertise in wholesale electricity market
23		rules, including those established by the Federal
24		Energy Regulatory Commission and regional transmission
25		organizations;
26		(E) expertise in credit and contract protocols;

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1		(F) adequate resources to perform and fulfill the
2		required functions and responsibilities; and
3		(G) the absence of a conflict of interest and
4		inappropriate bias for or against potential bidders or
5		the affected electric utilities.
6		(3) The Agency shall provide affected utilities and
7		other interested parties with the lists of qualified
8		experts or expert consulting firms identified through the
9		request for qualifications processes that are under
10		consideration to develop the procurement plans and to
11		serve as the procurement administrator. The Agency shall
12		also provide each qualified expert's or expert consulting
13		firm's response to the request for qualifications. All
14		information provided under this subparagraph shall also be
15		provided to the Commission. The Agency may provide by rule
16		for fees associated with supplying the information to
17		utilities and other interested parties. These parties
18		shall, within 5 business days, notify the Agency in
19		writing if they object to any experts or expert consulting
20		firms on the lists. Objections shall be based on:
21		(A) failure to satisfy qualification criteria;
22		(B) identification of a conflict of interest; or
23		(C) evidence of inappropriate bias for or against
24		potential bidders or the affected utilities.
25		The Agency shall remove experts or expert consulting
26		firms from the lists within 10 days if there is a

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1		reasonable basis for an objection and provide the updated
2		lists to the affected utilities and other interested
3		parties. If the Agency fails to remove an expert or expert
4		consulting firm from a list, an objecting party may seek
5		review by the Commission within 5 days thereafter by
6		filing a petition, and the Commission shall render a
7		ruling on the petition within 10 days. There is no right of
8		appeal of the Commission's ruling.
9		(4) The Agency shall issue requests for proposals to
10		the qualified experts or expert consulting firms to
11		develop a procurement plan for the affected utilities and
12		to serve as procurement administrator.
13		(5) The Agency shall select an expert or expert
14		consulting firm to develop procurement plans based on the
15		proposals submitted and shall award contracts of up to 5
16		years to those selected.
17		(6) The Agency shall select an expert or expert
18		consulting firm, with approval of the Commission, to serve
19		as procurement administrator based on the proposals
20		submitted. If the Commission rejects, within 5 days, the
21		Agency's selection, the Agency shall submit another
22		recommendation within 3 days based on the proposals
23		submitted. The Agency shall award a 5-year contract to the
24		expert or expert consulting firm so selected with
25		Commission approval.
26		(b) The experts or expert consulting firms retained by the

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1		Agency shall, as appropriate, prepare procurement plans, and
2		conduct a competitive procurement process as prescribed in
3		Section 16-111.5 of the Public Utilities Act, to ensure
4		adequate, 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, for
7		eligible retail customers of electric utilities that on
8		December 31, 2005 provided electric service to at least
9		100,000 customers in the State of Illinois, and for eligible
10		Illinois retail customers of small multi-jurisdictional
11		electric utilities that (i) on December 31, 2005 served less
12		than 100,000 customers in Illinois and (ii) request a
13		procurement plan for their Illinois jurisdictional load.
14		(c) Renewable portfolio standard.
15		(1)(A) The Agency shall develop a long-term renewable
16		resources procurement plan that shall include procurement
17		programs and competitive procurement events necessary to
18		meet the goals set forth in this subsection (c). The
19		initial long-term renewable resources procurement plan
20		shall be released for comment no later than 160 days after
21		June 1, 2017 (the effective date of Public Act 99-906).
22		The Agency shall review, and may revise on an expedited
23		basis, the long-term renewable resources procurement plan
24		at least every 2 years, which shall be conducted in
25		conjunction with the procurement plan under Section
26		16-111.5 of the Public Utilities Act to the extent

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1		practicable to minimize administrative expense. No later
2		than 120 days after the effective date of this amendatory
3		Act of the 103rd General Assembly, the Agency shall
4		release for comment a revision to the long-term renewable
5		resources procurement plan, updating elements of the most
6		recently approved plan as needed to comply with this
7		amendatory Act of the 103rd General Assembly, and any
8		long-term renewable resources procurement plan update
9		published by the Agency but not yet approved by the
10		Illinois Commerce Commission shall be withdrawn. The
11		long-term renewable resources procurement plans shall be
12		subject to review and approval by the Commission under
13		Section 16-111.5 of the Public Utilities Act.
14		(B) Subject to subparagraph (F) of this paragraph (1),
15		the long-term renewable resources procurement plan shall
16		attempt to meet the goals for procurement of renewable
17		energy credits at levels of at least the following overall
18		percentages: 13% by the 2017 delivery year; increasing by
19		at least 1.5% each delivery year thereafter to at least
20		25% by the 2025 delivery year; increasing by at least 3%
21		each delivery year thereafter to at least 40% by the 2030
22		delivery year, and continuing at no less than 40% for each
23		delivery year thereafter. The Agency shall attempt to
24		procure 50% by delivery year 2040. The Agency shall
25		determine the annual increase between delivery year 2030
26		and delivery year 2040, if any, taking into account energy

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1		demand, other energy resources, and other public policy
2		goals. In the event of a conflict between these goals and
3		the new wind, new photovoltaic, new geothermal heating and
4		cooling, and hydropower procurement requirements described
5		in items (i) through (iii) of subparagraph (C) of this
6		paragraph (1), the long-term plan shall prioritize
7		compliance with the new wind, new photovoltaic, new
8		geothermal heating and cooling, and hydropower procurement
9		requirements described in items (i) through (iii) of
10		subparagraph (C) of this paragraph (1) over the annual
11		percentage targets described in this subparagraph (B). The
12		Agency shall not comply with the annual percentage targets
13		described in this subparagraph (B) by procuring renewable
14		energy credits that are unlikely to lead to the
15		development of new renewable resources or new, modernized,
16		or retooled hydropower facilities.
17		For the delivery year beginning June 1, 2017, the
18		procurement plan shall attempt to include, subject to the
19		prioritization outlined in this subparagraph (B),
20		cost-effective renewable energy resources equal to at
21		least 13% of each utility's load for eligible retail
22		customers and 13% of the applicable portion of each
23		utility's load for retail customers who are not eligible
24		retail customers, which applicable portion shall equal 50%
25		of the utility's load for retail customers who are not
26		eligible retail customers on February 28, 2017.

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1		For the delivery year beginning June 1, 2018, the
2		procurement plan shall attempt to include, subject to the
3		prioritization outlined in this subparagraph (B),
4		cost-effective renewable energy resources equal to at
5		least 14.5% of each utility's load for eligible retail
6		customers and 14.5% of the applicable portion of each
7		utility's load for retail customers who are not eligible
8		retail customers, which applicable portion shall equal 75%
9		of the utility's load for retail customers who are not
10		eligible retail customers on February 28, 2017.
11		For the delivery year beginning June 1, 2019, and for
12		each year thereafter, the procurement plans shall attempt
13		to include, subject to the prioritization outlined in this
14		subparagraph (B), cost-effective renewable energy
15		resources equal to a minimum percentage of each utility's
16		load for all retail customers as follows: 16% by June 1,
17		2019; increasing by 1.5% each year thereafter to 25% by
18		June 1, 2025; and 25% by June 1, 2026; increasing by at
19		least 3% each delivery year thereafter to at least 40% by
20		the 2030 delivery year, and continuing at no less than 40%
21		for each delivery year thereafter. The Agency shall
22		attempt to procure 50% by delivery year 2040. The Agency
23		shall determine the annual increase between delivery year
24		2030 and delivery year 2040, if any, taking into account
25		energy demand, other energy resources, and other public
26		policy goals.

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1		For each delivery year, the Agency shall first
2		recognize each utility's obligations for that delivery
3		year under existing contracts. Any renewable energy
4		credits under existing contracts, including renewable
5		energy credits as part of renewable energy resources,
6		shall be used to meet the goals set forth in this
7		subsection (c) for the delivery year.
8		(C) The long-term renewable resources procurement plan
9		described in subparagraph (A) of this paragraph (1) shall
10		include the procurement of renewable energy credits from
11		new projects pursuant to the following terms:
12		(i) At least 10,000,000 renewable energy credits
13		delivered annually by the end of the 2021 delivery
14		year, and increasing ratably to reach 45,000,000
15		renewable energy credits delivered annually from new
16		wind and solar projects, from repowered wind projects,
17		or from retooled hydropower facilities by the end of
18		delivery year 2030 such that the goals in subparagraph
19		(B) of this paragraph (1) are met entirely by
20		procurements of renewable energy credits from new wind
21		and photovoltaic projects. Of that amount, to the
22		extent possible, the Agency shall endeavor to procure
23		45% from new and repowered wind and hydropower
24		projects and shall procure at least 55% from
25		photovoltaic projects. Of the amount to be procured
26		from photovoltaic projects, the Agency shall procure:

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1		at least 50% from solar photovoltaic projects using
2		the program outlined in subparagraph (K) of this
3		paragraph (1) from distributed renewable energy
4		generation devices or community renewable generation
5		projects; at least 47% from utility-scale solar
6		projects; at least 3% from brownfield site
7		photovoltaic projects that are not community renewable
8		generation projects. The Agency may propose
9		adjustments to these percentages, including
10		establishing percentage-based goals for the
11		procurement of renewable energy credits from
12		modernized or retooled hydropower facilities and
13		repowered wind projects, through its long-term
14		renewable resources plan described in subparagraph (A)
15		of this paragraph (1) as necessary based on developer
16		interest, market conditions, budget considerations,
17		resource adequacy needs, or other factors.
18		Notwithstanding the percentage-based goals as
19		described in this Section, the Agency shall develop a
20		Geothermal Homes and Businesses Program for the
21		procurement of renewable energy credits from
22		geothermal heating and cooling systems.
23		In developing the long-term renewable resources
24		procurement plan, the Agency shall consider other
25		approaches, in addition to competitive procurements,
26		that can be used to procure renewable energy credits

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1		from brownfield site photovoltaic projects and thereby
2		help return blighted or contaminated land to
3		productive use while enhancing public health and the
4		well-being of Illinois residents, including those in
5		environmental justice communities, as defined using
6		existing methodologies and findings used by the Agency
7		and its Administrator in its Illinois Solar for All
8		Program. The Agency shall also consider other
9		approaches, in addition to competitive procurements,
10		to procure renewable energy credits from new and
11		existing hydropower facilities to support the
12		development and maintenance of these facilities. The
13		Agency shall explore options to convert existing dams
14		but shall not consider approaches to develop new dams
15		where they do not already exist. To encourage the
16		continued operation of utility-scale wind projects,
17		the Agency shall consider and may propose other
18		approaches in addition to competitive procurements to
19		procure renewable energy credits from repowered wind
20		projects.
21		(ii) In any given delivery year, if forecasted
22		expenses are less than the maximum budget available
23		under subparagraph (E) of this paragraph (1), the
24		Agency shall continue to procure new renewable energy
25		credits until that budget is exhausted in the manner
26		outlined in item (i) of this subparagraph (C).

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1		(iii) For purposes of this Section:
2		"New wind projects" means wind renewable energy
3		facilities that are energized after June 1, 2017 for
4		the delivery year commencing June 1, 2017.
5		"New photovoltaic projects" means photovoltaic
6		renewable energy facilities that are energized after
7		June 1, 2017. Photovoltaic projects developed under
8		Section 1-56 of this Act shall not apply towards the
9		new photovoltaic project requirements in this
10		subparagraph (C).
11		"Repowered wind projects" means utility-scale wind
12		projects featuring the removal, replacement, or
13		expansion of turbines at an existing project site, as
14		defined in the long-term renewable resources
15		procurement plan, after the effective date of this
16		amendatory Act of the 103rd General Assembly.
17		Renewable energy credit contract awards used to
18		support repowered wind projects shall only cover the
19		incremental increase in facility electricity
20		production resultant from repowering.
21		"Geothermal heating and cooling system" means a
22		system located in this State that meets all of the
23		following requirements:
24		(I) the system exchanges thermal energy from
25		groundwater or a shallow ground source to generate
26		thermal energy through an electric geothermal heat

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1		pump or a system of electric geothermal heat pumps
2		interconnected with any geothermal extraction
3		facility that is (1) a closed loop or a series of
4		closed loop systems in which fluid is permanently
5		confined within a pipe or tubing and does not come
6		in contact with the outside environment or (2) an
7		open loop system in which ground or surface water
8		is circulated in an environmentally safe manner
9		directly into the facility and returned to the
10		same aquifer or surface water source;
11		(II) the system meets or exceeds federal
12		Energy Star product specification standards for
13		Geothermal Heat Pumps established on January 1,
14		2012, as clarified by the Environmental Protection
15		Agency guidance document released on February 28,
16		2012 entitled "Clarification to the Geothermal
17		Heat Pump Verification Testing Requirements and
18		Basic Model Group Definition", or any successor
19		standards that meet or exceed these standards;
20		(III) the system replaces or displaces less
21		efficient space or water heating systems,
22		regardless of fuel type;
23		(IV) the system replaces or displaces less
24		efficient space cooling systems, when applicable;
25		(V) the system does not feed electricity back
26		to the grid, as defined at the level of the

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1		geothermal heat pump; and
2		(VI) the system became operational on or after
3		the effective date of this amendatory Act of the
4		104th General Assembly.
5		For purposes of calculating whether the Agency has
6		procured enough new wind and solar renewable energy
7		credits required by this subparagraph (C), renewable
8		energy facilities that have a multi-year renewable
9		energy credit delivery contract with the utility
10		through at least delivery year 2030 shall be
11		considered new, however no renewable energy credits
12		from contracts entered into before June 1, 2021 shall
13		be used to calculate whether the Agency has procured
14		the correct proportion of new wind and new solar
15		contracts described in this subparagraph (C) for
16		delivery year 2021 and thereafter.
17		(iv) The Agency may implement additional measures,
18		including eligibility requirements, to ensure that new
19		wind projects and new photovoltaic projects supported
20		through renewable energy credit contract awards are a
21		result of a contract award and are otherwise developed
22		pursuant to the financial certainty provided through a
23		contract award.
24		(D) Renewable energy credits shall be cost effective.
25		For purposes of this subsection (c), "cost effective"
26		means that the costs of procuring renewable energy

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1		resources do not cause the limit stated in subparagraph
2		(E) of this paragraph (1) to be exceeded and, for
3		renewable energy credits procured through a competitive
4		procurement event, do not exceed benchmarks based on
5		market prices for like products in the region. For
6		purposes of this subsection (c), "like products" means
7		contracts for renewable energy credits from the same or
8		substantially similar technology, same or substantially
9		similar vintage (new or existing), the same or
10		substantially similar quantity, and the same or
11		substantially similar contract length and structure.
12		Benchmarks shall reflect development, financing, or
13		related costs resulting from requirements imposed through
14		other provisions of State law, including, but not limited
15		to, requirements in subparagraphs (P) and (Q) of this
16		paragraph (1) and the Renewable Energy Facilities
17		Agricultural Impact Mitigation Act. Confidential
18		benchmarks shall be developed by the procurement
19		administrator, in consultation with the Commission staff,
20		Agency staff, and the procurement monitor and shall be
21		subject to Commission review and approval. If price
22		benchmarks for like products in the region are not
23		available, the procurement administrator shall establish
24		price benchmarks based on publicly available data on
25		regional technology costs and expected current and future
26		regional energy prices. The benchmarks in this Section

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1		shall not be used to curtail or otherwise reduce
2		contractual obligations entered into by or through the
3		Agency prior to June 1, 2017 (the effective date of Public
4		Act 99-906).
5		(E) For purposes of this subsection (c), the required
6		procurement of cost-effective renewable energy resources
7		for a particular year commencing prior to June 1, 2017
8		shall be measured as a percentage of the actual amount of
9		electricity (megawatt-hours) supplied by the electric
10		utility to eligible retail customers in the delivery year
11		ending immediately prior to the procurement, and, for
12		delivery years commencing on and after June 1, 2017, the
13		required procurement of cost-effective renewable energy
14		resources for a particular year shall be measured as a
15		percentage of the actual amount of electricity
16		(megawatt-hours) delivered by the electric utility in the
17		delivery year ending immediately prior to the procurement,
18		to all retail customers in its service territory. For
19		purposes of this subsection (c), the amount paid per
20		kilowatthour means the total amount paid for electric
21		service expressed on a per kilowatthour basis. For
22		purposes of this subsection (c), the total amount paid for
23		electric service includes without limitation amounts paid
24		for supply, transmission, capacity, distribution,
25		surcharges, and add-on taxes.
26		Notwithstanding the requirements of this subsection

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1		(c), and except as provided in subparagraph (E-5) of
2		paragraph (1) of this subsection (c) or except as
3		otherwise authorized by the Commission in its approval of
4		the integrated resource plan under Section 16-202 of the
5		Public Utilities Act, the total of renewable energy
6		resources procured under the procurement plan for any
7		single year shall be subject to the limitations of this
8		subparagraph (E). Such procurement shall be reduced for
9		all retail customers based on the amount necessary to
10		limit the annual estimated average net increase due to the
11		costs of these resources included in the amounts paid by
12		eligible retail customers in connection with electric
13		service to no more than 4.25% of the amount paid per
14		kilowatthour by those customers during the year ending May
15		31, 2009, adjusted annually for inflation starting with
16		the first adjustment in the delivery year commencing June
17		1, 2026. For the purposes of this Section, the inflation
18		adjustment shall not be accrued or applied retroactively
19		prior to the effective date of this amendatory Act of the
20		104th General Assembly and shall apply prospectively
21		starting in 2025. The limitation shall be increased by an
22		additional 1.65 percentage points of the amount paid per
23		kilowatthour by eligible retail customers during the year
24		ending May 31, 2009 starting with the delivery year
25		commencing June 1, 2027. To arrive at a maximum dollar
26		amount of renewable energy resources to be procured for

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1		the particular delivery year, the resulting per
2		kilowatthour amount shall be applied to the actual amount
3		of kilowatthours of electricity delivered, or applicable
4		portion of such amount as specified in paragraph (1) of
5		this subsection (c), as applicable, by the electric
6		utility in the delivery year immediately prior to the
7		procurement to all retail customers in its service
8		territory. The calculations required by this subparagraph
9		(E) shall be made only once for each delivery year at the
10		time that the renewable energy resources are procured.
11		Once the determination as to the amount of renewable
12		energy resources to procure is made based on the
13		calculations set forth in this subparagraph (E) and the
14		contracts procuring those amounts are executed between the
15		seller and applicable electric utility, no subsequent rate
16		impact determinations shall be made and no adjustments to
17		those contract amounts shall be allowed. As provided in
18		subparagraph (E-5) of paragraph (1) of this subsection
19		(c), the seller shall be entitled to full, prompt, and
20		uninterrupted payment under the applicable contract
21		notwithstanding the application of this subparagraph (E),
22		and all costs incurred under such contracts shall be fully
23		recoverable by the electric utility as provided in this
24		Section.
25		(E-5) If, for a particular delivery year, the
26		limitation on the amount of renewable energy resources to

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1		be procured, as calculated pursuant to subparagraph (E) of
2		paragraph (1) of this subsection (c), would result in an
3		insufficient collection of funds to fully pay amounts due
4		to a seller under existing contracts executed under this
5		Section or executed under Section 1-56 of this Act, then
6		the following provisions shall apply to ensure full and
7		uninterrupted payment is made to such seller or sellers:
8		(i) If the electric utility has retained unspent
9		funds in an interest-bearing account as prescribed in
10		subsection (k) of Section 16-108 of the Public
11		Utilities Act, then the utility shall use those funds
12		to remit full payment to the sellers to ensure prompt
13		and uninterrupted payment of existing contractual
14		obligation.
15		(ii) If the funds described in item (i) of this
16		subparagraph (E-5) are insufficient to satisfy all
17		existing contractual obligations, then the electric
18		utility shall, nonetheless, remit full payment to the
19		sellers to ensure prompt and uninterrupted payment of
20		existing contractual obligations, provided that the
21		full costs shall be recoverable by the utility in
22		accordance with part (ee) of item (iv) of this
23		subsection (E-5).
24		(iii) The Agency shall promptly notify the
25		Commission that existing contractual obligations are
26		reasonably expected to exceed the maximum collection

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1		authorized under subparagraph (E) of paragraph (1) of
2		this subsection (c) for the applicable delivery year.
3		The Agency shall also explain and confirm how the
4		operation of items (i) and (ii) of this subparagraph
5		(E-5) ensures that the electric utility will continue
6		to make prompt and uninterrupted payment under
7		existing contractual obligations. The Agency shall
8		provide this information to the Commission through a
9		notice filed in the Commission docket approving the
10		Agency's operative Long-Term Renewable Resources
11		Procurement Plan that includes the applicable delivery
12		year.
13		(iv) The Agency shall suspend or reduce new
14		contract awards for the procurement of renewable
15		energy credits until an Agency determination is made
16		under subparagraph (E) that additional procurements
17		would not cause the rate impact limitation of
18		subparagraph (E) to be exceeded. At least once
19		annually after the notice provided for in item (iii)
20		of this subparagraph (E-5) is made, the Agency shall
21		analyze existing contract obligations, projected
22		prices for indexed renewable energy credit contracts
23		executed under item (v) of subparagraph (G) of
24		paragraph (1) of subsection (c) of Section 1-75 of
25		this Act, and expected collections authorized under
26		subparagraph (E) to determine whether and to what

SB0025 Enrolled - 215 - LRB104 07069 BAB 17106 b
1		extent the limitations of subparagraph (E) would be
2		exceeded by additional renewable energy credit
3		procurement contract awards.
4		(aa) If the Agency determines that additional
5		renewable energy credit procurement contract
6		awards could be made without exceeding the
7		limitations of subparagraph (E), then the
8		procurements shall be authorized at a scale
9		determined not to exceed the limitations of
10		subparagraph (E) in a manner consistent with the
11		priorities of this Section.
12		(bb) If the Agency determines that additional
13		renewable energy credit procurement contract
14		awards cannot be made without exceeding the
15		limitations of subparagraph (E), then the Agency
16		shall suspend any new contract awards for the
17		procurement of renewable energy credits until a
18		new rate impact determination is made under
19		subparagraph (E).
20		(cc) Agency determinations made under this
21		item (iv) shall be detailed and comprehensive and,
22		if not made through the Agency's Long-Term
23		Renewable Resources Procurement Plan, shall be
24		filed as a compliance filing in the most recent
25		docketed proceeding approving the Agency's
26		Long-Term Renewable Resources Procurement Plan.

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1		(dd) With respect to the procurement of
2		renewable energy credits authorized through
3		programs administered under subsection (b) of
4		Section 1-56 and subparagraphs (K) through (M) of
5		paragraph (1) of subsection (k) of Section 1-75 of
6		this Act, the award of contracts for the
7		procurement of renewable energy credits shall be
8		suspended or reduced only at the conclusion of the
9		program year in which the notice provided for
10		under item (iii) of this subparagraph (E-5) is
11		made.
12		(ee) The contract shall provide that, so long
13		as at least one of: (i) the cost recovery
14		mechanisms referenced in subsection (k) of Section
15		16-108 and subsection (l) of Section 16-111.5 of
16		the Public Utilities Act remains in full force
17		without limitation or (ii) the utility is
18		otherwise authorized and or entitled to full,
19		prompt, and uninterrupted recovery of its costs
20		through any other mechanism, then such seller
21		shall be entitled to full, prompt, and
22		uninterrupted payment under the applicable
23		contract notwithstanding the application of this
24		subparagraph (E).
25		(F) If the limitation on the amount of renewable
26		energy resources procured in subparagraph (E) of this

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1		paragraph (1) prevents the Agency from meeting all of the
2		goals in this subsection (c), the Agency's long-term plan
3		shall prioritize compliance with the requirements of this
4		subsection (c) regarding renewable energy credits in the
5		following order:
6		(i) renewable energy credits under existing
7		contractual obligations as of June 1, 2021;
8		(i-5) funding for the Illinois Solar for All
9		Program, as described in subparagraph (O) of this
10		paragraph (1);
11		(ii) renewable energy credits necessary to comply
12		with the new wind and new photovoltaic procurement
13		requirements described in items (i) through (iii) of
14		subparagraph (C) of this paragraph (1); and
15		(iii) renewable energy credits necessary to meet
16		the remaining requirements of this subsection (c).
17		(G) The following provisions shall apply to the
18		Agency's procurement of renewable energy credits under
19		this subsection (c):
20		(i) Notwithstanding whether a long-term renewable
21		resources procurement plan has been approved, the
22		Agency shall conduct an initial forward procurement
23		for renewable energy credits from new utility-scale
24		wind projects within 160 days after June 1, 2017 (the
25		effective date of Public Act 99-906). For the purposes
26		of this initial forward procurement, the Agency shall

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1		solicit 15-year contracts for delivery of 1,000,000
2		renewable energy credits delivered annually from new
3		utility-scale wind projects to begin delivery on June
4		1, 2019, if available, but not later than June 1, 2021,
5		unless the project has delays in the establishment of
6		an operating interconnection with the applicable
7		transmission or distribution system as a result of the
8		actions or inactions of the transmission or
9		distribution provider, or other causes for force
10		majeure as outlined in the procurement contract, in
11		which case, not later than June 1, 2022. Payments to
12		suppliers of renewable energy credits shall commence
13		upon delivery. Renewable energy credits procured under
14		this initial procurement shall be included in the
15		Agency's long-term plan and shall apply to all
16		renewable energy goals in this subsection (c).
17		(ii) Notwithstanding whether a long-term renewable
18		resources procurement plan has been approved, the
19		Agency shall conduct an initial forward procurement
20		for renewable energy credits from new utility-scale
21		solar projects and brownfield site photovoltaic
22		projects within one year after June 1, 2017 (the
23		effective date of Public Act 99-906). For the purposes
24		of this initial forward procurement, the Agency shall
25		solicit 15-year contracts for delivery of 1,000,000
26		renewable energy credits delivered annually from new

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1		utility-scale solar projects and brownfield site
2		photovoltaic projects to begin delivery on June 1,
3		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. The Agency may
11		structure this initial procurement in one or more
12		discrete procurement events. Payments to suppliers of
13		renewable energy credits shall commence upon delivery.
14		Renewable energy credits procured under this initial
15		procurement shall be included in the Agency's
16		long-term plan and shall apply to all renewable energy
17		goals in this subsection (c).
18		(iii) Notwithstanding whether the Commission has
19		approved the periodic long-term renewable resources
20		procurement plan revision described in Section
21		16-111.5 of the Public Utilities Act, the Agency shall
22		conduct at least one subsequent forward procurement
23		for renewable energy credits from new utility-scale
24		wind projects, new utility-scale solar projects, and
25		new brownfield site photovoltaic projects within 240
26		days after the effective date of this amendatory Act

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1		of the 102nd General Assembly in quantities necessary
2		to meet the requirements of subparagraph (C) of this
3		paragraph (1) through the delivery year beginning June
4		1, 2021.
5		(iv) Notwithstanding whether the Commission has
6		approved the periodic long-term renewable resources
7		procurement plan revision described in Section
8		16-111.5 of the Public Utilities Act, the Agency shall
9		open capacity for each category in the Adjustable
10		Block program within 90 days after the effective date
11		of this amendatory Act of the 102nd General Assembly
12		manner:
13		(1) The Agency shall open the first block of
14		annual capacity for the category described in item
15		(i) of subparagraph (K) of this paragraph (1). The
16		first block of annual capacity for item (i) shall
17		be for at least 75 megawatts of total nameplate
18		capacity. The price of the renewable energy credit
19		for this block of capacity shall be 4% less than
20		the price of the last open block in this category.
21		Projects on a waitlist shall be awarded contracts
22		first in the order in which they appear on the
23		waitlist. Notwithstanding anything to the
24		contrary, for those renewable energy credits that
25		qualify and are procured under this subitem (1) of
26		this item (iv), the renewable energy credit

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1		delivery contract value shall be paid in full,
2		based on the estimated generation during the first
3		15 years of operation, by the contracting
4		utilities at the time that the facility producing
5		the renewable energy credits is interconnected at
6		the distribution system level of the utility and
7		verified as energized and in compliance by the
8		Program Administrator. The electric utility shall
9		receive and retire all renewable energy credits
10		generated by the project for the first 15 years of
11		operation. Renewable energy credits generated by
12		the project thereafter shall not be transferred
13		under the renewable energy credit delivery
14		contract with the counterparty electric utility.
15		(2) The Agency shall open the first block of
16		annual capacity for the category described in item
17		(ii) of subparagraph (K) of this paragraph (1).
18		The first block of annual capacity for item (ii)
19		shall be for at least 75 megawatts of total
20		nameplate capacity.
21		(A) The price of the renewable energy
22		credit for any project on a waitlist for this
23		category before the opening of this block
24		shall be 4% less than the price of the last
25		open block in this category. Projects on the
26		waitlist shall be awarded contracts first in

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1		the order in which they appear on the
2		waitlist. Any projects that are less than or
3		equal to 25 kilowatts in size on the waitlist
4		for this capacity shall be moved to the
5		waitlist for paragraph (1) of this item (iv).
6		Notwithstanding anything to the contrary,
7		projects that were on the waitlist prior to
8		opening of this block shall not be required to
9		be in compliance with the requirements of
10		subparagraph (Q) of this paragraph (1) of this
11		subsection (c). Notwithstanding anything to
12		the contrary, for those renewable energy
13		credits procured from projects that were on
14		the waitlist for this category before the
15		opening of this block 20% of the renewable
16		energy credit delivery contract value, based
17		on the estimated generation during the first
18		15 years of operation, shall be paid by the
19		contracting utilities at the time that the
20		facility producing the renewable energy
21		credits is interconnected at the distribution
22		system level of the utility and verified as
23		energized by the Program Administrator. The
24		remaining portion shall be paid ratably over
25		the subsequent 4-year period. The electric
26		utility shall receive and retire all renewable

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1		energy credits generated by the project during
2		the first 15 years of operation. Renewable
3		energy credits generated by the project
4		thereafter shall not be transferred under the
5		renewable energy credit delivery contract with
6		the counterparty electric utility.
7		(B) The price of renewable energy credits
8		for any project not on the waitlist for this
9		category before the opening of the block shall
10		be determined and published by the Agency.
11		Projects not on a waitlist as of the opening
12		of this block shall be subject to the
13		requirements of subparagraph (Q) of this
14		paragraph (1), as applicable. Projects not on
15		a waitlist as of the opening of this block
16		shall be subject to the contract provisions
17		outlined in item (iii) of subparagraph (L) of
18		this paragraph (1). The Agency shall strive to
19		publish updated prices and an updated
20		renewable energy credit delivery contract as
21		quickly as possible.
22		(3) For opening the first 2 blocks of annual
23		capacity for projects participating in item (iii)
24		of subparagraph (K) of paragraph (1) of subsection
25		(c), projects shall be selected exclusively from
26		those projects on the ordinal waitlists of

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1		community renewable generation projects
2		established by the Agency based on the status of
3		those ordinal waitlists as of December 31, 2020,
4		and only those projects previously determined to
5		be eligible for the Agency's April 2019 community
6		solar project selection process.
7		The first 2 blocks of annual capacity for item
8		(iii) shall be for 250 megawatts of total
9		nameplate capacity, with both blocks opening
10		simultaneously under the schedule outlined in the
11		paragraphs below. Projects shall be selected as
12		follows:
13		(A) The geographic balance of selected
14		projects shall follow the Group classification
15		found in the Agency's Revised Long-Term
16		Renewable Resources Procurement Plan, with 70%
17		of capacity allocated to projects on the Group
18		B waitlist and 30% of capacity allocated to
19		projects on the Group A waitlist.
20		(B) Contract awards for waitlisted
21		projects shall be allocated proportionate to
22		the total nameplate capacity amount across
23		both ordinal waitlists associated with that
24		applicant firm or its affiliates, subject to
25		the following conditions.
26		(i) Each applicant firm having a

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1		waitlisted project eligible for selection
2		shall receive no less than 500 kilowatts
3		in awarded capacity across all groups, and
4		no approved vendor may receive more than
5		20% of each Group's waitlist allocation.
6		(ii) Each applicant firm, upon
7		receiving an award of program capacity
8		proportionate to its waitlisted capacity,
9		may then determine which waitlisted
10		projects it chooses to be selected for a
11		contract award up to that capacity amount.
12		(iii) Assuming all other program
13		requirements are met, applicant firms may
14		adjust the nameplate capacity of applicant
15		projects without losing waitlist
16		eligibility, so long as no project is
17		greater than 2,000 kilowatts in size.
18		(iv) Assuming all other program
19		requirements are met, applicant firms may
20		adjust the expected production associated
21		with applicant projects, subject to
22		verification by the Program Administrator.
23		(C) After a review of affiliate
24		information and the current ordinal waitlists,
25		the Agency shall announce the nameplate
26		capacity award amounts associated with

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1		applicant firms no later than 90 days after
2		the effective date of this amendatory Act of
3		the 102nd General Assembly.
4		(D) Applicant firms shall submit their
5		portfolio of projects used to satisfy those
6		contract awards no less than 90 days after the
7		Agency's announcement. The total nameplate
8		capacity of all projects used to satisfy that
9		portfolio shall be no greater than the
10		Agency's nameplate capacity award amount
11		associated with that applicant firm. An
12		applicant firm may decline, in whole or in
13		part, its nameplate capacity award without
14		penalty, with such unmet capacity rolled over
15		to the next block opening for project
16		selection under item (iii) of subparagraph (K)
17		of this subsection (c). Any projects not
18		included in an applicant firm's portfolio may
19		reapply without prejudice upon the next block
20		reopening for project selection under item
21		(iii) of subparagraph (K) of this subsection
22		(c).
23		(E) The renewable energy credit delivery
24		contract shall be subject to the contract and
25		payment terms outlined in item (iv) of
26		subparagraph (L) of this subsection (c).

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1		Contract instruments used for this
2		subparagraph shall contain the following
3		terms:
4		(i) Renewable energy credit prices
5		shall be fixed, without further adjustment
6		under any other provision of this Act or
7		for any other reason, at 10% lower than
8		prices applicable to the last open block
9		for this category, inclusive of any adders
10		available for achieving a minimum of 50%
11		of subscribers to the project's nameplate
12		capacity being residential or small
13		commercial customers with subscriptions of
14		below 25 kilowatts in size;
15		(ii) A requirement that a minimum of
16		50% of subscribers to the project's
17		nameplate capacity be residential or small
18		commercial customers with subscriptions of
19		below 25 kilowatts in size;
20		(iii) Permission for the ability of a
21		contract holder to substitute projects
22		with other waitlisted projects without
23		penalty should a project receive a
24		non-binding estimate of costs to construct
25		the interconnection facilities and any
26		required distribution upgrades associated

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1		with that project of greater than 30 cents
2		per watt AC of that project's nameplate
3		capacity. In developing the applicable
4		contract instrument, the Agency may
5		consider whether other circumstances
6		outside of the control of the applicant
7		firm should also warrant project
8		substitution rights.
9		The Agency shall publish a finalized
10		updated renewable energy credit delivery
11		contract developed consistent with these terms
12		and conditions no less than 30 days before
13		applicant firms must submit their portfolio of
14		projects pursuant to item (D).
15		(F) To be eligible for an award, the
16		applicant firm shall certify that not less
17		than prevailing wage, as determined pursuant
18		to the Illinois Prevailing Wage Act, was or
19		will be paid to employees who are engaged in
20		construction activities associated with a
21		selected project.
22		(4) The Agency shall open the first block of
23		annual capacity for the category described in item
24		(iv) of subparagraph (K) of this paragraph (1).
25		The first block of annual capacity for item (iv)
26		shall be for at least 50 megawatts of total

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1		nameplate capacity. Renewable energy credit prices
2		shall be fixed, without further adjustment under
3		any other provision of this Act or for any other
4		reason, at the price in the last open block in the
5		category described in item (ii) of subparagraph
6		(K) of this paragraph (1). Pricing for future
7		blocks of annual capacity for this category may be
8		adjusted in the Agency's second revision to its
9		Long-Term Renewable Resources Procurement Plan.
10		Projects in this category shall be subject to the
11		contract terms outlined in item (iv) of
12		subparagraph (L) of this paragraph (1).
13		(5) The Agency shall open the equivalent of 2
14		years of annual capacity for the category
15		described in item (v) of subparagraph (K) of this
16		paragraph (1). The first block of annual capacity
17		for item (v) shall be for at least 10 megawatts of
18		total nameplate capacity. Notwithstanding the
19		provisions of item (v) of subparagraph (K) of this
20		paragraph (1), for the purpose of this initial
21		block, the agency shall accept new project
22		applications intended to increase the diversity of
23		areas hosting community solar projects, the
24		business models of projects, and the size of
25		projects, as described by the Agency in its
26		long-term renewable resources procurement plan

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1		that is approved as of the effective date of this
2		amendatory Act of the 102nd General Assembly.
3		Projects in this category shall be subject to the
4		contract terms outlined in item (iii) of
5		subsection (L) of this paragraph (1).
6		(6) The Agency shall open the first blocks of
7		annual capacity for the category described in item
8		(vi) of subparagraph (K) of this paragraph (1),
9		with allocations of capacity within the block
10		generally matching the historical share of block
11		capacity allocated between the category described
12		in items (i) and (ii) of subparagraph (K) of this
13		paragraph (1). The first two blocks of annual
14		capacity for item (vi) shall be for at least 75
15		megawatts of total nameplate capacity. The price
16		of renewable energy credits for the blocks of
17		capacity shall be 4% less than the price of the
18		last open blocks in the categories described in
19		items (i) and (ii) of subparagraph (K) of this
20		paragraph (1). Pricing for future blocks of annual
21		capacity for this category may be adjusted in the
22		Agency's second revision to its Long-Term
23		Renewable Resources Procurement Plan. Projects in
24		this category shall be subject to the applicable
25		contract terms outlined in items (ii) and (iii) of
26		subparagraph (L) of this paragraph (1).

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1		(v) Upon the effective date of this amendatory Act
2		of the 102nd General Assembly, for all competitive
3		procurements and any procurements of renewable energy
4		credit from new utility-scale wind and new
5		utility-scale photovoltaic projects, the Agency shall
6		procure indexed renewable energy credits and direct
7		respondents to offer a strike price.
8		(1) The purchase price of the indexed
9		renewable energy credit payment shall be
10		calculated for each settlement period. That
11		payment, for any settlement period, shall be equal
12		to the difference resulting from subtracting the
13		strike price from the index price for that
14		settlement period. If this difference results in a
15		negative number, the indexed REC counterparty
16		shall owe the seller the absolute value multiplied
17		by the quantity of energy produced in the relevant
18		settlement period. If this difference results in a
19		positive number, the seller shall owe the indexed
20		REC counterparty this amount multiplied by the
21		quantity of energy produced in the relevant
22		settlement period.
23		(2) Parties shall cash settle every month,
24		summing up all settlements (both positive and
25		negative, if applicable) for the prior month.
26		(3) To ensure funding in the annual budget

SB0025 Enrolled - 232 - LRB104 07069 BAB 17106 b
1		established under subparagraph (E) for indexed
2		renewable energy credit procurements for each year
3		of the term of such contracts, which must have a
4		minimum tenure of 20 calendar years, the
5		procurement administrator, Agency, Commission
6		staff, and procurement monitor shall quantify the
7		annual cost of the contract by utilizing one or
8		more an industry-standard, third-party forward
9		price curves curve for energy at the appropriate
10		hub or load zone, including the estimated
11		magnitude and timing of the price effects related
12		to federal carbon controls. Each forward price
13		curve shall contain a specific value of the
14		forecasted market price of electricity for each
15		annual delivery year of the contract. For
16		procurement planning purposes, the impact on the
17		annual budget for the cost of indexed renewable
18		energy credits for each delivery year shall be
19		determined as the expected annual contract
20		expenditure for that year, equaling the difference
21		between (i) the sum across all relevant contracts
22		of the applicable strike price multiplied by
23		contract quantity and (ii) the sum across all
24		relevant contracts of the forward price curve for
25		the applicable load zone for that year multiplied
26		by contract quantity. The contracting utility

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1		shall not assume an obligation in excess of the
2		estimated annual cost of the contracts for indexed
3		renewable energy credits. Forward curves shall be
4		revised on an annual basis as updated forward
5		price curves are released and filed with the
6		Commission in the proceeding approving the
7		Agency's most recent long-term renewable resources
8		procurement plan. If the expected contract spend
9		is higher or lower than the total quantity of
10		contracts multiplied by the forward price curve
11		value for that year, the forward price curve shall
12		be updated by the procurement administrator, in
13		consultation with the Agency, Commission staff,
14		and procurement monitors, using then-currently
15		available price forecast data and additional
16		budget dollars shall be obligated or reobligated
17		as appropriate.
18		(4) To ensure that indexed renewable energy
19		credit prices remain predictable and affordable,
20		the Agency may consider the institution of a price
21		collar on REC prices paid under indexed renewable
22		energy credit procurements establishing floor and
23		ceiling REC prices applicable to indexed REC
24		contract prices. Any price collars applicable to
25		indexed REC procurements shall be proposed by the
26		Agency through its long-term renewable resources

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1		procurement plan.
2		(vi) All procurements under this subparagraph (G),
3		including the procurement of renewable energy credits
4		from hydropower facilities, shall comply with the
5		geographic requirements in subparagraph (I) of this
6		paragraph (1) and shall follow the procurement
7		processes and procedures described in this Section and
8		Section 16-111.5 of the Public Utilities Act to the
9		extent practicable, and these processes and procedures
10		may be expedited to accommodate the schedule
11		established by this subparagraph (G). To ensure the
12		successful development of new renewable energy
13		projects supported through competitive procurements,
14		for any procurements conducted under items (i), (ii),
15		(iii), and (v) of this subparagraph (G) and any other
16		procurement of new utility-scale wind or utility-scale
17		solar projects that were entered into prior to January
18		1, 2025, the Agency shall allow, upon a demonstration
19		of need to ensure the commercial viability of a
20		project, for a one-time, post-award renegotiation of
21		select contract terms prior to the project's
22		commercial operation date through bilateral
23		negotiation between the Agency, the buyer, and a
24		winning bidder. Contract terms subject to
25		renegotiation may include the project map, as defined
26		under the applicable competitive solicitation, the

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

SB0025 Enrolled - 236 - LRB104 07069 BAB 17106 b
1		winning bidder reach an agreement on amended terms,
2		then, upon petition by the winning bidder or current
3		seller, the Commission shall issue an order directing
4		the utility counterparty to execute an amendment
5		drafted by the Agency with the revised terms to the
6		renewable energy credit contract, the product order,
7		or both. The Agency shall provide the amendment to the
8		utility within 15 business days after the Commission's
9		order, and the utility shall execute the amendment no
10		more than 7 calendar days after delivery by the
11		Agency.
12		(vii) On and after the effective date of this
13		amendatory Act of the 103rd General Assembly, for all
14		procurements of renewable energy credits from
15		hydropower facilities, the Agency shall establish
16		contract terms designed to optimize existing
17		hydropower facilities through modernization or
18		retooling and establish new hydropower facilities at
19		existing dams. Procurements made under this item (vii)
20		shall prioritize projects located in designated
21		environmental justice communities, as defined in
22		subsection (b) of Section 1-56 of this Act, or in
23		projects located in units of local government with
24		median incomes that do not exceed 82% of the median
25		income of the State.
26		(H) The procurement of renewable energy resources for

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

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

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1		For delivery years beginning June 1, 2019 and
2		each year thereafter, the maximum amount of
3		renewable energy credits to be supplied by an
4		alternative retail electric supplier under this
5		subparagraph (H) shall be 68% multiplied by 50%
6		multiplied by 16% multiplied by the amount of
7		metered electricity (megawatt-hours) delivered by
8		the alternative retail electric supplier to
9		Illinois retail customers during the delivery year
10		ending May 31, 2016, provided that the 16% value
11		shall increase by 1.5% each delivery year
12		thereafter to 25% by the delivery year beginning
13		June 1, 2025, and thereafter the 25% value shall
14		apply to each delivery year.
15		For each delivery year, the total amount of
16		renewable energy credits supplied by all alternative
17		retail electric suppliers under this subparagraph (H)
18		shall not exceed 9% of the Illinois target renewable
19		energy credit quantity. The Illinois target renewable
20		energy credit quantity for the delivery year beginning
21		June 1, 2018 is 14.5% multiplied by the total amount of
22		metered electricity (megawatt-hours) delivered in the
23		delivery year immediately preceding that delivery
24		year, provided that the 14.5% shall increase by 1.5%
25		each delivery year thereafter to 25% by the delivery
26		year beginning June 1, 2025, and thereafter the 25%

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1		value shall apply to each delivery year.
2		If the requirements set forth in items (i) through
3		(iii) of this subparagraph (H) are met, the charges
4		that would otherwise be applicable to the retail
5		customers of the alternative retail electric supplier
6		under paragraph (6) of this subsection (c) for the
7		applicable delivery year shall be reduced by the ratio
8		of the quantity of renewable energy credits supplied
9		by the alternative retail electric supplier compared
10		to that supplier's target renewable energy credit
11		quantity. The supplier's target renewable energy
12		credit quantity for the delivery year beginning June
13		1, 2018 is 14.5% multiplied by the total amount of
14		metered electricity (megawatt-hours) delivered by the
15		alternative retail supplier in that delivery year,
16		provided that the 14.5% shall increase by 1.5% each
17		delivery year thereafter to 25% by the delivery year
18		beginning June 1, 2025, and thereafter the 25% value
19		shall apply to each delivery year.
20		On or before April 1 of each year, the Agency shall
21		annually publish a report on its website that
22		identifies the aggregate amount of renewable energy
23		credits supplied by alternative retail electric
24		suppliers under this subparagraph (H).
25		(I) The Agency shall design its long-term renewable
26		energy procurement plan to maximize the State's interest

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1		in the health, safety, and welfare of its residents,
2		including but not limited to minimizing sulfur dioxide,
3		nitrogen oxide, particulate matter and other pollution
4		that adversely affects public health in this State,
5		increasing fuel and resource diversity in this State,
6		enhancing the reliability and resiliency of the
7		electricity distribution system in this State, meeting
8		goals to limit carbon dioxide emissions under federal or
9		State law, and contributing to a cleaner and healthier
10		environment for the citizens of this State. In order to
11		further these legislative purposes, renewable energy
12		credits shall be eligible to be counted toward the
13		renewable energy requirements of this subsection (c) if
14		they are generated from facilities located in this State.
15		The Agency may qualify renewable energy credits from
16		facilities located in states adjacent to Illinois or
17		renewable energy credits associated with the electricity
18		generated by a utility-scale wind energy facility or
19		utility-scale photovoltaic facility and transmitted by a
20		qualifying direct current project described in subsection
21		(b-5) of Section 8-406 of the Public Utilities Act to a
22		delivery point on the electric transmission grid located
23		in this State or a state adjacent to Illinois, if the
24		generator demonstrates and the Agency determines that the
25		operation of such facility or facilities will help promote
26		the State's interest in the health, safety, and welfare of

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1		its residents based on the public interest criteria
2		described above. For the purposes of this Section,
3		renewable resources that are delivered via a high voltage
4		direct current converter station located in Illinois shall
5		be deemed generated in Illinois at the time and location
6		the energy is converted to alternating current by the high
7		voltage direct current converter station if the high
8		voltage direct current transmission line: (i) after the
9		effective date of this amendatory Act of the 102nd General
10		Assembly, was constructed with a project labor agreement;
11		(ii) is capable of transmitting electricity at 525kv;
12		(iii) has an Illinois converter station located and
13		interconnected in the region of the PJM Interconnection,
14		LLC; (iv) does not operate as a public utility; and (v) if
15		the high voltage direct current transmission line was
16		energized after June 1, 2023. To ensure that the public
17		interest criteria are applied to the procurement and given
18		full effect, the Agency's long-term procurement plan shall
19		describe in detail how each public interest factor shall
20		be considered and weighted for facilities located in
21		states adjacent to Illinois.
22		(J) In order to promote the competitive development of
23		renewable energy resources in furtherance of the State's
24		interest in the health, safety, and welfare of its
25		residents, renewable energy credits shall not be eligible
26		to be counted toward the renewable energy requirements of

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1		this subsection (c) if they are sourced from a generating
2		unit whose costs were being recovered through rates
3		regulated by this State or any other state or states on or
4		after January 1, 2017. Each contract executed to purchase
5		renewable energy credits under this subsection (c) shall
6		provide for the contract's termination if the costs of the
7		generating unit supplying the renewable energy credits
8		subsequently begin to be recovered through rates regulated
9		by this State or any other state or states; and each
10		contract shall further provide that, in that event, the
11		supplier of the credits must return 110% of all payments
12		received under the contract. Amounts returned under the
13		requirements of this subparagraph (J) shall be retained by
14		the utility and all of these amounts shall be used for the
15		procurement of additional renewable energy credits from
16		new wind or new photovoltaic resources as defined in this
17		subsection (c). The long-term plan shall provide that
18		these renewable energy credits shall be procured in the
19		next procurement event.
20		Notwithstanding the limitations of this subparagraph
21		(J), renewable energy credits sourced from generating
22		units that are constructed, purchased, owned, or leased by
23		an electric utility as part of an approved project,
24		program, or pilot under Section 1-56 of this Act shall be
25		eligible to be counted toward the renewable energy
26		requirements of this subsection (c), regardless of how the

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1		costs of these units are recovered. As long as a
2		generating unit or an identifiable portion of a generating
3		unit has not had and does not have its costs recovered
4		through rates regulated by this State or any other state,
5		HVDC renewable energy credits associated with that
6		generating unit or identifiable portion thereof shall be
7		eligible to be counted toward the renewable energy
8		requirements of this subsection (c).
9		(K) The long-term renewable resources procurement plan
10		developed by the Agency in accordance with subparagraph
11		(A) of this paragraph (1) shall include an Adjustable
12		Block program for the procurement of renewable energy
13		credits from new photovoltaic projects that are
14		distributed renewable energy generation devices or new
15		photovoltaic community renewable generation projects. The
16		Adjustable Block program shall be generally designed to
17		provide for the steady, predictable, and sustainable
18		growth of new solar photovoltaic development in Illinois.
19		To this end, the Adjustable Block program shall provide a
20		transparent annual schedule of prices and quantities to
21		enable the photovoltaic market to scale up and for
22		renewable energy credit prices to adjust at a predictable
23		rate over time. The prices set by the Adjustable Block
24		program can be reflected as a set value or as the product
25		of a formula.
26		The Adjustable Block program shall include for each

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1		category of eligible projects for each delivery year: a
2		single block of nameplate capacity, a price for renewable
3		energy credits within that block, and the terms and
4		conditions for securing a spot on a waitlist once the
5		block is fully committed or reserved. Except as outlined
6		below, the waitlist of projects in a given year will carry
7		over to apply to the subsequent year when another block is
8		opened. Only projects energized on or after June 1, 2017
9		shall be eligible for the Adjustable Block program. For
10		each category for each delivery year the Agency shall
11		determine the amount of generation capacity in each block,
12		and the purchase price for each block, provided that the
13		purchase price provided and the total amount of generation
14		in all blocks for all categories shall be sufficient to
15		meet the goals in this subsection (c). The Agency shall
16		strive to issue a single block sized to provide for
17		stability and market growth. The Agency shall establish
18		program eligibility requirements that ensure that projects
19		that enter the program are sufficiently mature to indicate
20		a demonstrable path to completion. The Agency may
21		periodically review its prior decisions establishing the
22		amount of generation capacity in each block, and the
23		purchase price for each block, and may propose, on an
24		expedited basis, changes to these previously set values,
25		including but not limited to redistributing these amounts
26		and the available funds as necessary and appropriate,

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1		subject to Commission approval as part of the periodic
2		plan revision process described in Section 16-111.5 of the
3		Public Utilities Act. The Agency may define different
4		block sizes, purchase prices, or other distinct terms and
5		conditions for projects located in different utility
6		service territories if the Agency deems it necessary to
7		meet the goals in this subsection (c).
8		The Adjustable Block program shall include the
9		following categories in at least the following amounts:
10		(i) At least 20% from distributed renewable energy
11		generation devices with a nameplate capacity of no
12		more than 25 kilowatts.
13		(ii) At least 20% from distributed renewable
14		energy generation devices with a nameplate capacity of
15		more than 25 kilowatts and no more than 5,000
16		kilowatts. The Agency may create sub-categories within
17		this category to account for the differences between
18		projects for small commercial customers, large
19		commercial customers, and public or non-profit
20		customers. A project shall not be colocated with one
21		or more other distributed renewable energy generation
22		projects if the aggregate nameplate capacity of the
23		projects exceeds 5,000 kilowatts AC. Notwithstanding
24		any other provision of this Section, if 2 or more
25		projects are developed, owned, or controlled by or
26		originate from the same developer or an affiliated

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1		developer and the projects serve affiliated loads, the
2		projects shall be colocated if the projects are
3		located on adjacent parcels. If 2 or more projects are
4		developed, owned, or controlled by or originate from
5		the same developer and the projects serve unaffiliated
6		loads, the projects may be colocated if documentation
7		indicates affiliated management and ownership in the
8		pre-development, development, construction, and
9		management of the projects and the projects are
10		located on a single or adjacent parcels.
11		Notwithstanding any subsequent transfer, assignment,
12		or conveyance of ownership or development rights to
13		separate legal entities, the Agency shall consider, in
14		its determination of whether projects are affiliated,
15		evidence that the projects were pre-developed by the
16		same legal entity or an affiliated entity. If the
17		Agency determines the projects are affiliated, the
18		projects shall be treated as colocated for purposes of
19		aggregate nameplate capacity limitations and renewable
20		energy credit pricing adjustments. The Agency shall
21		make exceptions on a case-by-case basis if it is
22		demonstrated that projects on one parcel or projects
23		on adjacent parcels are unaffiliated. For purposes of
24		determining colocation, an approved vendor who submits
25		an application for a distributed renewable energy
26		generation project shall be required to submit an

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1		affidavit attesting that the project is not affiliated
2		with any other distributed renewable energy generation
3		project such that, if the 2 projects were deemed
4		colocated, the projects would exceed the 5,000
5		kilowatts nameplate capacity limitation. The receipt
6		of an affidavit shall not restrict the Agency's
7		ability to investigate and determine whether the
8		project is, in fact, colocated.
9		For purposes of this item (ii):
10		"Affiliate" has the meaning given to that term in
11		subitem (3) of item (iii) of this subparagraph (K).
12		"Colocated" means 2 or more distributed renewable
13		energy generation projects that are located on a
14		single parcel, except for projects where the owner of
15		the applicable retail electric account is confirmed to
16		be unaffiliated and the projects serve distinct
17		electrical loads.
18		"Control" has the meaning given to that term in
19		subitem (3) of item (iii) of this subparagraph (K).
20		(iii) At least 30% from photovoltaic community
21		renewable generation projects. Capacity for this
22		category for the first 2 delivery years after the
23		effective date of this amendatory Act of the 102nd
24		General Assembly shall be allocated to waitlist
25		projects as provided in paragraph (3) of item (iv) of
26		subparagraph (G). Starting in the third delivery year

SB0025 Enrolled - 249 - LRB104 07069 BAB 17106 b
1		after the effective date of this amendatory Act of the
2		102nd General Assembly or earlier if the Agency
3		determines there is additional capacity needed for to
4		meet previous delivery year requirements, the
5		following shall apply:
6		(1) the Agency shall select projects on a
7		first-come, first-serve basis, however the Agency
8		may suggest additional methods to prioritize
9		projects that are submitted at the same time;
10		(2) projects shall have subscriptions of 25 kW
11		or less for at least 50% of the facility's
12		nameplate capacity and the Agency shall price the
13		renewable energy credits with that as a factor;
14		(3) projects shall not be colocated with one
15		or more other photovoltaic community renewable
16		generation projects such that the aggregate
17		nameplate capacity exceeds 10,000 kilowatts. The
18		total nameplate capacity of colocated projects
19		shall be the sum of the nameplate capacities of
20		the individual projects. For purposes of this
21		subitem (3), separate legal formation of approved
22		vendors, owners, or developers shall not preclude
23		a finding of affiliation by the Agency. Evidence
24		of affiliation may include, but is not limited to,
25		shared personnel, common contractual or financing
26		arrangements, a shared interconnection agreement,

SB0025 Enrolled - 250 - LRB104 07069 BAB 17106 b
1		distinct interconnection agreements obtained by
2		the same pre-development entity that are
3		subsequently sold to distinct legal entities,
4		familial relationships, or any demonstrable
5		pattern of coordinated action in the
6		pre-development, development, construction, or
7		management of photovoltaic community renewable
8		generation projects.
9		The Agency shall determine affiliation based
10		on evidence that projects either (i) share a
11		common origin on a parcel that has been subdivided
12		in the 5 years before the date of application or
13		(ii) were pre-developed before the beginning of
14		construction by the same legal entity or an
15		affiliated legal entity. The determination shall
16		be made notwithstanding any subsequent transfer,
17		assignment, or conveyance of ownership or
18		development rights to separate legal entities. If
19		the Agency determines the projects are affiliated,
20		the projects shall be treated as colocated for the
21		purposes of aggregate nameplate capacity
22		limitations and renewable energy credit pricing
23		adjustments. The Agency shall make exceptions to
24		this subitem (3) on a case-by-case basis if it is
25		demonstrated that projects on one parcel or
26		projects on adjacent parcels are unaffiliated.

SB0025 Enrolled - 251 - LRB104 07069 BAB 17106 b
1		A parcel shall not be divided into multiple
2		parcels within the 5 years before the submission
3		of a project application. If a parcel is divided
4		within the preceding 5 years, a colocation
5		determination shall be made based on the
6		boundaries of the previous undivided parcel.
7		For purposes of determining colocation, an
8		approved vendor who submits an application for a
9		community renewable generation project shall be
10		required to submit an affidavit attesting that (i)
11		the parcel on which the project is sited has not
12		been subdivided within the 5 years preceding the
13		project application and (ii) the project is not
14		affiliated with any other community renewable
15		energy project in a manner that would cause the 2
16		projects, if deemed colocated, to exceed the
17		10,000 kilowatt nameplate capacity limitation. The
18		receipt of an affidavit shall not restrict the
19		Agency's ability to investigate and determine
20		whether the project is colocated.
21		Multiple community solar projects sited on
22		distinct structures located on a single parcel
23		shall be considered colocated and must demonstrate
24		that the projects are unaffiliated in order to not
25		be considered colocated. Each colocated project
26		shall receive the renewable energy credit price

SB0025 Enrolled - 252 - LRB104 07069 BAB 17106 b
1		corresponding to the total, aggregated nameplate
2		capacity of the colocated systems, as determined
3		at the time the second project's application is
4		submitted to the Agency. If the second colocated
5		project has been constructed and placed in service
6		prior to application, and was placed in service
7		more than 2 years after Commission approval of the
8		original project, the colocation pricing
9		adjustment shall not apply, and each project shall
10		receive the standalone renewable energy credit
11		price for its individual capacity.
12		For purposes of this subitem (3):
13		"Affiliate" means any other entity that,
14		directly or indirectly through one or more
15		intermediaries, is controlled by or is under
16		common control of the primary entity or a third
17		entity. "Affiliate" includes family members for
18		the purposes of colocation between projects.
19		"Affiliate" does not include entities that have
20		shared sales or revenue-sharing arrangements or
21		common debt and equity financing arrangements.
22		"Colocated" means 2 or more photovoltaic
23		community renewable generation projects located on
24		a single parcel or adjacent parcels, unless it is
25		demonstrated that the projects are developed by
26		unaffiliated entities.

SB0025 Enrolled - 253 - LRB104 07069 BAB 17106 b
1		"Control" means the possession, directly or
2		indirectly, of the power to direct the management
3		and policies of an entity , as defined in the
4		Agency's first revised long-term renewable
5		resources procurement plan approved by the
6		Commission on February 18, 2020, such that the
7		aggregate nameplate capacity exceeds 5,000
8		kilowatts; and
9		(4) projects greater than 2 MW may not apply
10		until after the approval of the Agency's revised
11		Long-Term Renewable Resources Procurement Plan
12		after the effective date of this amendatory Act of
13		the 102nd General Assembly.
14		(iv) At least 15% from distributed renewable
15		generation devices or photovoltaic community renewable
16		generation projects installed on public school land.
17		The Agency may create subcategories within this
18		category to account for the differences between
19		project size or location. Projects located within
20		environmental justice communities or within
21		Organizational Units that fall within Tier 1 or Tier 2
22		shall be given priority. Each of the Agency's periodic
23		updates to its long-term renewable resources
24		procurement plan to incorporate the procurement
25		described in this subparagraph (iv) shall also include
26		the proposed quantities or blocks, pricing, and

SB0025 Enrolled - 254 - LRB104 07069 BAB 17106 b
1		contract terms applicable to the procurement as
2		indicated herein. In each such update and procurement,
3		the Agency shall set the renewable energy credit price
4		and establish payment terms for the renewable energy
5		credits procured pursuant to this subparagraph (iv)
6		that make it feasible and affordable for public
7		schools to install photovoltaic distributed renewable
8		energy devices on their premises, including, but not
9		limited to, those public schools subject to the
10		prioritization provisions of this subparagraph. For
11		the purposes of this item (iv):
12		"Environmental Justice Community" shall have the
13		same meaning set forth in the Agency's long-term
14		renewable resources procurement plan;
15		"Organization Unit", "Tier 1" and "Tier 2" shall
16		have the meanings set for in Section 18-8.15 of the
17		School Code;
18		"Public schools" shall have the meaning set forth
19		in Section 1-3 of the School Code and includes public
20		institutions of higher education, as defined in the
21		Board of Higher Education Act.
22		(v) At least 5% from community-driven community
23		solar projects intended to provide more direct and
24		tangible connection and benefits to the communities
25		which they serve or in which they operate and,
26		additionally, to increase the variety of community

SB0025 Enrolled - 255 - LRB104 07069 BAB 17106 b
1		solar locations, models, and options in Illinois. As
2		part of its long-term renewable resources procurement
3		plan, the Agency shall develop selection criteria for
4		projects participating in this category. Nothing in
5		this Section shall preclude the Agency from creating a
6		selection process that maximizes community ownership
7		and community benefits in selecting projects to
8		receive renewable energy credits. Selection criteria
9		shall include:
10		(1) community ownership or community
11		wealth-building;
12		(2) additional direct and indirect community
13		benefit, beyond project participation as a
14		subscriber, including, but not limited to,
15		economic, environmental, social, cultural, and
16		physical benefits;
17		(3) meaningful involvement in project
18		organization and development by community members
19		or nonprofit organizations or public entities
20		located in or serving the community;
21		(4) engagement in project operations and
22		management by nonprofit organizations, public
23		entities, or community members; and
24		(5) whether a project is developed in response
25		to a site-specific RFP developed by community
26		members or a nonprofit organization or public

SB0025 Enrolled - 256 - LRB104 07069 BAB 17106 b
1		entity located in or serving the community.
2		Selection criteria may also prioritize projects
3		that:
4		(1) are developed in collaboration with or to
5		provide complementary opportunities for the Clean
6		Jobs Workforce Network Program, the Illinois
7		Climate Works Preapprenticeship Program, the
8		Returning Residents Clean Jobs Training Program,
9		the Clean Energy Contractor Incubator Program, or
10		the Clean Energy Primes Contractor Accelerator
11		Program;
12		(2) increase the diversity of locations of
13		community solar projects in Illinois, including by
14		locating in urban areas and population centers;
15		(3) are located in Equity Investment Eligible
16		Communities;
17		(4) are not greenfield projects;
18		(5) serve only local subscribers;
19		(6) have a nameplate capacity that does not
20		exceed 500 kW;
21		(7) are developed by an equity eligible
22		contractor; or
23		(8) otherwise meaningfully advance the goals
24		of providing more direct and tangible connection
25		and benefits to the communities which they serve
26		or in which they operate and increasing the

SB0025 Enrolled - 257 - LRB104 07069 BAB 17106 b
1		variety of community solar locations, models, and
2		options in Illinois.
3		For the purposes of this item (v):
4		"Community" means a social unit in which people
5		come together regularly to effect change; a social
6		unit in which participants are marked by a cooperative
7		spirit, a common purpose, or shared interests or
8		characteristics; or a space understood by its
9		residents to be delineated through geographic
10		boundaries or landmarks.
11		"Community benefit" means a range of services and
12		activities that provide affirmative, economic,
13		environmental, social, cultural, or physical value to
14		a community; or a mechanism that enables economic
15		development, high-quality employment, and education
16		opportunities for local workers and residents, or
17		formal monitoring and oversight structures such that
18		community members may ensure that those services and
19		activities respond to local knowledge and needs.
20		"Community ownership" means an arrangement in
21		which an electric generating facility is, or over time
22		will be, in significant part, owned collectively by
23		members of the community to which an electric
24		generating facility provides benefits; members of that
25		community participate in decisions regarding the
26		governance, operation, maintenance, and upgrades of

SB0025 Enrolled - 258 - LRB104 07069 BAB 17106 b
1		and to that facility; and members of that community
2		benefit from regular use of that facility.
3		Terms and guidance within these criteria that are
4		not defined in this item (v) shall be defined by the
5		Agency, with stakeholder input, during the development
6		of the Agency's long-term renewable resources
7		procurement plan. The Agency shall develop regular
8		opportunities for projects to submit applications for
9		projects under this category, and develop selection
10		criteria that gives preference to projects that better
11		meet individual criteria as well as projects that
12		address a higher number of criteria.
13		(vi) At least 10% from distributed renewable
14		energy generation devices, which includes distributed
15		renewable energy devices with a nameplate capacity
16		under 5,000 kilowatts or photovoltaic community
17		renewable generation projects, from applicants that
18		are equity eligible contractors. The Agency may create
19		subcategories within this category to account for the
20		differences between project size and type. The Agency
21		shall propose to increase the percentage in this item
22		(vi) over time to 40% based on factors, including, but
23		not limited to, the number of equity eligible
24		contractors and capacity used in this item (vi) in
25		previous delivery years.
26		The Agency shall propose a payment structure for

SB0025 Enrolled - 259 - LRB104 07069 BAB 17106 b
1		contracts executed pursuant to this paragraph under
2		which, upon a demonstration of qualification or need
3		under criteria established by the Agency that is
4		focused on supporting small and emerging businesses
5		and businesses that most acutely face barriers to the
6		access of capital, applicant firms are advanced
7		capital disbursed after contract execution but before
8		the contracted project's energization. The amount or
9		percentage of capital advanced prior to project
10		energization shall be sufficient to both cover any
11		increase in development costs resulting from
12		prevailing wage requirements or project-labor
13		agreements, and designed to overcome barriers in
14		access to capital faced by equity eligible
15		contractors. The amount or percentage of advanced
16		capital may vary by subcategory within this category
17		and by an applicant's demonstration of need, with such
18		levels to be established through the Long-Term
19		Renewable Resources Procurement Plan authorized under
20		subparagraph (A) of paragraph (1) of subsection (c) of
21		this Section and any application requirements or
22		evaluation criteria developed pursuant to the Plan.
23		Contracts developed featuring capital advanced
24		prior to a project's energization shall feature
25		provisions to ensure both the successful development
26		of applicant projects and the delivery of the

SB0025 Enrolled - 260 - LRB104 07069 BAB 17106 b
1		renewable energy credits for the full term of the
2		contract, including ongoing collateral requirements
3		and other provisions deemed necessary by the Agency,
4		and may include energization timelines longer than for
5		comparable project types. The percentage or amount of
6		capital advanced prior to project energization shall
7		not operate to increase the overall contract value,
8		however contracts executed under this subparagraph may
9		feature renewable energy credit prices higher than
10		those offered to similar projects participating in
11		other categories. Capital advanced prior to
12		energization shall serve to reduce the ratable
13		payments made after energization under items (ii) and
14		(iii) of subparagraph (L) or payments made for each
15		renewable energy credit delivery under item (iv) of
16		subparagraph (L).
17		For projects developed under this item (vi), the
18		Agency shall take steps to encourage higher portions
19		of contract value to be provided to equity eligible
20		contractors and to support equity eligible persons who
21		participate in this Program and who exercise control
22		and actively manage their businesses and their
23		businesses' contractual projects. These steps may
24		include, but are not limited to, differentiated REC
25		prices, exceptions or exemptions, and other mechanisms
26		and requirements for nonnominal contract value to be

SB0025 Enrolled - 261 - LRB104 07069 BAB 17106 b
1		provided to equity eligible contractors and equity
2		eligible persons as a prerequisite to Program
3		participation. Any steps taken shall aim to encourage
4		and grow the meaningful participation of equity
5		eligible contractors in this State's clean energy
6		economy. All entities participating under this item
7		(vi) shall comply with the minimum equity standard set
8		forth under Section 1-75.
9		(vii) The remaining capacity shall be allocated by
10		the Agency in order to respond to market demand. The
11		Agency shall allocate any discretionary capacity prior
12		to the beginning of each delivery year.
13		(viii) The Agency, through its long-term renewable
14		resources procurement plan, may implement solutions to
15		maintain stable and consistent REC offerings allocated
16		to systems described in item (i) of this subparagraph
17		(K) to avoid gaps in availability during a delivery
18		year, including, but not limited to, creating a
19		floating block of REC capacity in a given delivery
20		year.
21		To the extent there is uncontracted capacity from any
22		block in any of categories (i) through (vi) at the end of a
23		delivery year, the Agency shall redistribute that capacity
24		to one or more other categories giving priority to
25		categories with projects on a waitlist. The redistributed
26		capacity shall be added to the annual capacity in the

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1		subsequent delivery year, and the price for renewable
2		energy credits shall be the price for the new delivery
3		year. Redistributed capacity shall not be considered
4		redistributed when determining whether the goals in this
5		subsection (K) have been met.
6		Notwithstanding anything to the contrary, as the
7		Agency increases the capacity in item (vi) to 40% over
8		time, the Agency may reduce the capacity of items (i)
9		through (v) proportionate to the capacity of the
10		categories of projects in item (vi), to achieve a balance
11		of project types.
12		The Adjustable Block program shall be designed to
13		ensure that renewable energy credits are procured from
14		projects in diverse locations and are not concentrated in
15		a few regional areas.
16		(L) Notwithstanding provisions for advancing capital
17		prior to project energization found in item (vi) of
18		subparagraph (K), the procurement of photovoltaic
19		renewable energy credits under items (i) through (vi) of
20		subparagraph (K) of this paragraph (1) shall otherwise be
21		subject to the following contract and payment terms:
22		(i) (Blank).
23		(ii) Unless otherwise provided for in the Agency's
24		approved long-term plan, for For those renewable
25		energy credits that qualify and are procured under
26		item (i) of subparagraph (K) of this paragraph (1),

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1		and any similar category projects that are procured
2		under item (vi) of subparagraph (K) of this paragraph
3		(1) that qualify and are procured under item (vi), the
4		contract length shall be 15 years. Beginning on the
5		effective date of this amendatory Act of the 104th
6		General Assembly, and including the remainder of
7		program year 2026-2027, 50% of the renewable energy
8		credit delivery contract value, based on the estimated
9		generation during the first 15 years of operation,
10		shall be paid The renewable energy credit delivery
11		contract value shall be paid in full, based on the
12		estimated generation during the first 15 years of
13		operation, by the contracting utilities at the time
14		that the facility producing the renewable energy
15		credits is interconnected at the distribution system
16		level of the utility and verified as energized and
17		compliant by the Program Administrator. The remaining
18		portion of the renewable energy credit delivery
19		contract value shall be paid ratably over the
20		subsequent 6-year period. Relative to a contract
21		structure under which the full renewable energy credit
22		delivery contract value shall be paid in full at the
23		time of interconnection and verification of
24		energization, the Agency shall consider the impact of
25		deferred payments across the subsequent payment period
26		when establishing renewable energy credit prices. The

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1		electric utility shall receive and retire all
2		renewable energy credits generated by the project for
3		the first 15 years of operation. Renewable energy
4		credits generated by the project thereafter shall not
5		be transferred under the renewable energy credit
6		delivery contract with the counterparty electric
7		utility.
8		(iii) Unless otherwise provided for in the
9		Agency's approved long-term plan, for For those
10		renewable energy credits that qualify and are procured
11		under item (ii) and (v) of subparagraph (K) of this
12		paragraph (1) and any like projects similar category
13		that qualify and are procured under items (iv) and
14		item (vi), the contract length shall be 15 years. 15%
15		of the renewable energy credit delivery contract
16		value, based on the estimated generation during the
17		first 15 years of operation, shall be paid by the
18		contracting utilities at the time that the facility
19		producing the renewable energy credits is
20		interconnected at the distribution system level of the
21		utility and verified as energized and compliant by the
22		Program Administrator. The remaining portion shall be
23		paid ratably over the subsequent 6-year period. The
24		electric utility shall receive and retire all
25		renewable energy credits generated by the project for
26		the first 15 years of operation. Renewable energy

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1		credits generated by the project thereafter shall not
2		be transferred under the renewable energy credit
3		delivery contract with the counterparty electric
4		utility.
5		(iv) Unless otherwise provided for in the Agency's
6		approved long-term plan, for For those renewable
7		energy credits that qualify and are procured under
8		item items (iii) and (iv) of subparagraph (K) of this
9		paragraph (1), and any like projects that qualify and
10		are procured under items (iv) and item (vi), the
11		renewable energy credit delivery contract length shall
12		be 20 years and shall be paid over the delivery term,
13		not to exceed during each delivery year the contract
14		price multiplied by the estimated annual renewable
15		energy credit generation amount. If generation of
16		renewable energy credits during a delivery year
17		exceeds the estimated annual generation amount, the
18		excess renewable energy credits shall be carried
19		forward to future delivery years and shall not expire
20		during the delivery term. If generation of renewable
21		energy credits during a delivery year, including
22		carried forward excess renewable energy credits, if
23		any, is less than the estimated annual generation
24		amount, payments during such delivery year will not
25		exceed the quantity generated plus the quantity
26		carried forward multiplied by the contract price. The

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1		electric utility shall receive all renewable energy
2		credits generated by the project during the first 20
3		years of operation and retire all renewable energy
4		credits paid for under this item (iv) and return at the
5		end of the delivery term all renewable energy credits
6		that were not paid for. Renewable energy credits
7		generated by the project thereafter shall not be
8		transferred under the renewable energy credit delivery
9		contract with the counterparty electric utility.
10		Notwithstanding the preceding, for those projects
11		participating under item (iii) of subparagraph (K),
12		the contract price for a delivery year shall be based
13		on subscription levels as measured on the higher of
14		the first business day of the delivery year or the
15		first business day 6 months after the first business
16		day of the delivery year. Subscription of 90% of
17		nameplate capacity or greater shall be deemed to be
18		fully subscribed for the purposes of this item (iv).
19		For projects receiving a 20-year delivery contract,
20		REC prices shall be adjusted downward for consistency
21		with the incentive levels previously determined to be
22		necessary to support projects under 15-year delivery
23		contracts, taking into consideration any additional
24		new requirements placed on the projects, including,
25		but not limited to, labor standards.
26		(v) Each contract shall include provisions to

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1		ensure the delivery of the estimated quantity of
2		renewable energy credits and ongoing collateral
3		requirements and other provisions deemed appropriate
4		by the Agency.
5		(vi) The utility shall be the counterparty to the
6		contracts executed under this subparagraph (L) that
7		are approved by the Commission under the process
8		described in Section 16-111.5 of the Public Utilities
9		Act. No contract shall be executed for an amount that
10		is less than one renewable energy credit per year.
11		(vii) If, at any time, approved applications for
12		the Adjustable Block program exceed funds collected by
13		the electric utility or would cause the Agency to
14		exceed the limitation described in subparagraph (E) of
15		this paragraph (1) on the amount of renewable energy
16		resources that may be procured, then the Agency may
17		consider future uncommitted funds to be reserved for
18		these contracts on a first-come, first-served basis.
19		(viii) Nothing in this Section shall require the
20		utility to advance any payment or pay any amounts that
21		exceed the actual amount of revenues anticipated to be
22		collected by the utility under paragraph (6) of this
23		subsection (c) and subsection (k) of Section 16-108 of
24		the Public Utilities Act inclusive of eligible funds
25		collected in prior years and alternative compliance
26		payments for use by the utility.

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1		(ix) Notwithstanding other requirements of this
2		subparagraph (L), no modification shall be required to
3		Adjustable Block program contracts if they were
4		already executed prior to the establishment, approval,
5		and implementation of new contract forms as a result
6		of this amendatory Act of the 102nd General Assembly.
7		(x) Contracts may be assignable, but only to
8		entities first deemed by the Agency to have met
9		program terms and requirements applicable to direct
10		program participation. In developing contracts for the
11		delivery of renewable energy credits, the Agency shall
12		be permitted to establish fees applicable to each
13		contract assignment.
14		(M) The Agency shall be authorized to retain one or
15		more experts or expert consulting firms to develop,
16		administer, implement, operate, and evaluate the
17		Adjustable Block program described in subparagraph (K) of
18		this paragraph (1), as well as the Geothermal Homes and
19		Businesses Program described in subparagraph (S) of this
20		paragraph (1), and the Agency shall retain the consultant
21		or consultants in the same manner, to the extent
22		practicable, as the Agency retains others to administer
23		provisions of this Act, including, but not limited to, the
24		procurement administrator. The selection of experts and
25		expert consulting firms and the procurement process
26		described in this subparagraph (M) are exempt from the

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1		requirements of Section 20-10 of the Illinois Procurement
2		Code, under Section 20-10 of that Code. The Agency shall
3		strive to minimize administrative expenses in the
4		implementation of the Adjustable Block program.
5		The Program Administrator may charge application fees
6		to participating firms to cover the cost of program
7		administration. Any application fee amounts shall
8		initially be determined through the long-term renewable
9		resources procurement plan, and modifications to any
10		application fee that deviate more than 25% from the
11		Commission's approved value must be approved by the
12		Commission as a long-term plan revision under Section
13		16-111.5 of the Public Utilities Act. The Agency shall
14		consider stakeholder feedback when making adjustments to
15		application fees and shall notify stakeholders in advance
16		of any planned changes.
17		In addition to covering the costs of program
18		administration, the Agency, in conjunction with its
19		Program Administrator, may also use the proceeds of such
20		fees charged to participating firms to support public
21		education and ongoing regional and national coordination
22		with nonprofit organizations, public bodies, and others
23		engaged in the implementation of renewable energy
24		incentive programs or similar initiatives. This work may
25		include developing papers and reports, hosting regional
26		and national conferences, and other work deemed necessary

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1		by the Agency to position the State of Illinois as a
2		national leader in renewable energy incentive program
3		development and administration.
4		The Agency and its consultant or consultants shall
5		monitor block activity, share program activity with
6		stakeholders and conduct quarterly meetings to discuss
7		program activity and market conditions. If necessary, the
8		Agency may make prospective administrative adjustments to
9		the Adjustable Block program and the Geothermal Homes and
10		Businesses Program design, such as making adjustments to
11		purchase prices as necessary to achieve the goals of this
12		subsection (c). Program modifications to any block price
13		that do not deviate from the Commission's approved value
14		by more than 10% shall take effect immediately and are not
15		subject to Commission review and approval. Program
16		modifications to any block price that deviate more than
17		10% from the Commission's approved value must be approved
18		by the Commission as a long-term plan amendment under
19		Section 16-111.5 of the Public Utilities Act. The Agency
20		shall consider stakeholder feedback when making
21		adjustments to the Adjustable Block and the Geothermal
22		Homes and Businesses Program design and shall notify
23		stakeholders in advance of any planned changes.
24		The Agency and its program administrators for both the
25		Adjustable Block program, and the Illinois Solar for All
26		Program, and the Geothermal Homes and Businesses Program

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1		consistent with the requirements of this subsection (c)
2		and subsection (b) of Section 1-56 of this Act, shall
3		propose the Adjustable Block program terms, conditions,
4		and requirements, including the prices to be paid for
5		renewable energy credits, where applicable, and
6		requirements applicable to participating entities and
7		project applications, through the development, review, and
8		approval of the Agency's long-term renewable resources
9		procurement plan described in this subsection (c) and
10		paragraph (5) of subsection (b) of Section 16-111.5 of the
11		Public Utilities Act. Terms, conditions, and requirements
12		for program participation shall include the following:
13		(i) The Agency shall establish a registration
14		process for entities seeking to qualify for
15		program-administered incentive funding and establish
16		baseline qualifications for vendor approval. The
17		Agency shall also establish program requirements and
18		minimum contract terms for vendors and others involved
19		in the marketing, sale, installation, and financing of
20		distributed generation systems and community solar
21		subscriptions to prevent misleading marketing and
22		abusive practices and to otherwise protect customers.
23		The Agency must maintain a list of approved entities
24		on each program's website, and may revoke a vendor's
25		ability to receive program-administered incentive
26		funding status upon a determination that the vendor

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1		failed to comply with contract terms, the law, or
2		other program requirements.
3		(ii) The Agency shall establish program
4		requirements and minimum contract terms to ensure
5		projects are properly installed and produce their
6		expected amounts of energy. Program requirements may
7		include on-site inspections and photo documentation of
8		projects under construction. The Agency may require
9		repairs, alterations, or additions to remedy any
10		material deficiencies discovered. Vendors who have a
11		disproportionately high number of deficient systems
12		may lose their eligibility to continue to receive
13		State-administered incentive funding through Agency
14		programs and procurements.
15		(iii) To discourage deceptive marketing or other
16		bad faith business practices, the Agency may require
17		direct program participants, including agents
18		operating on their behalf, to provide standardized
19		disclosures to a customer prior to that customer's
20		execution of a contract for the development of a
21		distributed generation system, or a subscription to a
22		community solar project, or the development of a
23		geothermal heating and cooling system.
24		(iv) The Agency shall establish one or multiple
25		Consumer Complaints Centers to accept complaints
26		regarding businesses that participate in, or otherwise

SB0025 Enrolled - 273 - LRB104 07069 BAB 17106 b
1		benefit from, State-administered incentive funding
2		through Agency-administered programs. The Agency shall
3		maintain a public database of complaints with any
4		confidential or particularly sensitive information
5		redacted from public entries.
6		(v) Through a filing in the proceeding for the
7		approval of its long-term renewable energy resources
8		procurement plan, the Agency shall provide an annual
9		written report to the Illinois Commerce Commission
10		documenting the frequency and nature of complaints and
11		any enforcement actions taken in response to those
12		complaints.
13		(vi) The Agency shall schedule regular meetings
14		with representatives of the Office of the Attorney
15		General, the Illinois Commerce Commission, consumer
16		protection groups, and other interested stakeholders
17		to share relevant information about consumer
18		protection, project compliance, and complaints
19		received.
20		(vii) To the extent that complaints received
21		implicate the jurisdiction of the Office of the
22		Attorney General, the Illinois Commerce Commission, or
23		local, State, or federal law enforcement, the Agency
24		shall also refer complaints to those entities as
25		appropriate.
26		(viii) The Agency may, at its discretion,

SB0025 Enrolled - 274 - LRB104 07069 BAB 17106 b
1		establish a registration process for entities, or a
2		subset of entities, that provide financing for
3		consumers for the purchase of distributed renewable
4		generation devices. The Agency may establish baseline
5		qualifications for financing entity approval,
6		including defining the circumstances under which
7		financing entities may be subject to registration. The
8		Agency may also establish program requirements for
9		entities that provide financing for the purchase of
10		distributed renewable generation devices, which may
11		include marketing and disclosure requirements, other
12		requirements as further defined by the Agency through
13		its long-term plan, and any consumer protection
14		requirements developed or modified thereto. If the
15		Agency establishes a registration process for
16		financing entities, the Agency may revoke a financing
17		entity's approval in a program upon a determination
18		that the financing entity failed to comply with
19		contract terms, the law, or other program
20		requirements. The Agency may also establish program
21		requirements that prohibit distributed renewable
22		generation devices intending to apply for
23		program-administered incentive funding from receiving
24		program funding if the consumer's purchase of the
25		device was financed by an entity whose approval status
26		in the program has been revoked. These registration

SB0025 Enrolled - 275 - LRB104 07069 BAB 17106 b
1		requirements may apply to entities that finance
2		projects intended to apply for program-administered
3		incentive funding even if those entities do not
4		receive any portion of the program-administered
5		incentive funding.
6		(ix) The Agency, at its discretion, may require
7		that vendors, as part of the application and annual
8		recertification process, present the Agency or its
9		designee with a security bond equal to an amount
10		determined to be reasonable by the Agency. The bond
11		shall be for the benefit of customers harmed by the
12		vendor's violation of Agency requirements or other
13		applicable laws or regulations. The Agency may
14		determine that it is reasonable to have no bond
15		requirement for some categories of vendors or enhanced
16		bond requirements for vendors that the Agency has
17		deemed to pose more acute risks.
18		(x) For distributed renewable generation devices,
19		the Agency may, in its discretion, establish
20		provisions that restrict, prohibit, or create
21		additional requirements for distributed renewable
22		generation device sales or financing offers through
23		which the customer is promised the pass-through of a
24		portion or all of the payments received by the
25		approved vendor for the delivery of renewable energy
26		credits only after the receipt of such payment by the

SB0025 Enrolled - 276 - LRB104 07069 BAB 17106 b
1		approved vendor. The requirements may include the use
2		of an escrow process developed by the Agency through
3		which renewable energy credit payments are made to an
4		escrow agent who then disburses the promised amount to
5		the customer and the remainder to the vendor. The
6		requirements in this item (x) shall in no way prohibit
7		the upfront discounting of the purchase price, lease
8		payment, or power purchase agreement rate based on the
9		anticipated receipt of renewable energy credit
10		contract payments by the approved vendor.
11		(xi) To the extent that distributed renewable
12		generation device sales or financing offers through
13		which the customer is promised the pass-through of a
14		portion or all of the payments received by the vendor
15		for the delivery of renewable energy credits after the
16		receipt of such payment by the vendor are permitted,
17		the following requirements may be implemented, at the
18		Agency's discretion, in a time and manner determined
19		by the Agency:
20		(I) the vendor shall submit proof of customer
21		payments to the Agency as the Agency deems
22		necessary; and
23		(II) the vendor shall represent and warrant on
24		a form developed by the Agency that the vendor is
25		not insolvent, has not voluntarily filed for
26		bankruptcy, and has not been subject to or

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1		threatened with involuntary insolvency.
2		(xii) To ensure that customers receive full and
3		uninterrupted benefits and services promised by
4		vendors, the Agency may propose additional solutions
5		through its long-term renewable resources procurement
6		plan described in this subsection (c) and paragraph
7		(5) of subsection (b) of Section 16-111.5 of the
8		Public Utilities Act. The solutions may allow for
9		collections made pursuant to subsection (k) of Section
10		16-108 of the Public Utilities Act to support the
11		programs and procurements outlined in paragraph (1) of
12		subsection (c) of this Section to be leveraged to (1)
13		ensure that a vendor's promised payments are received
14		by customers, (2) incentivize vendors to establish
15		service agreements with customers whose original
16		vendor has become nonresponsive, (3) ensure that
17		customers receive restitution for financial harm
18		proven to be caused by a program vendor or its
19		designee, or (4) otherwise ensure that customers do
20		not suffer loss or harm through activities supported
21		by the Adjustable Block program and the Illinois Solar
22		for All Program.
23		(N) The Agency shall establish the terms, conditions,
24		and program requirements for photovoltaic community
25		renewable generation projects with a goal to expand access
26		to a broader group of energy consumers, to ensure robust

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1		participation opportunities for residential and small
2		commercial customers and those who cannot install
3		renewable energy on their own properties. Subject to
4		reasonable limitations, any plan approved by the
5		Commission shall allow subscriptions to community
6		renewable generation projects to be portable and
7		transferable. For purposes of this subparagraph (N),
8		"portable" means that subscriptions may be retained by the
9		subscriber even if the subscriber relocates or changes its
10		address within the same utility service territory; and
11		"transferable" means that a subscriber may assign or sell
12		subscriptions to another person within the same utility
13		service territory.
14		Through the development of its long-term renewable
15		resources procurement plan, the Agency may consider
16		whether community renewable generation projects utilizing
17		technologies other than photovoltaics should be supported
18		through State-administered incentive funding, and may
19		issue requests for information to gauge market demand.
20		Electric utilities shall provide a monetary credit to
21		a subscriber's subsequent bill for service for the
22		proportional output of a community renewable generation
23		project attributable to that subscriber as specified in
24		Section 16-107.5 of the Public Utilities Act.
25		The Agency shall purchase renewable energy credits
26		from subscribed shares of photovoltaic community renewable

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1		generation projects through the Adjustable Block program
2		described in subparagraph (K) of this paragraph (1) or
3		through the Illinois Solar for All Program described in
4		Section 1-56 of this Act. The electric utility shall
5		purchase any unsubscribed energy from community renewable
6		generation projects that are Qualifying Facilities ("QF")
7		under the electric utility's tariff for purchasing the
8		output from QFs under Public Utilities Regulatory Policies
9		Act of 1978.
10		The owners of and any subscribers to a community
11		renewable generation project shall not be considered
12		public utilities or alternative retail electricity
13		suppliers under the Public Utilities Act solely as a
14		result of their interest in or subscription to a community
15		renewable generation project and shall not be required to
16		become an alternative retail electric supplier by
17		participating in a community renewable generation project
18		with a public utility.
19		(O) For the delivery year beginning June 1, 2018, the
20		long-term renewable resources procurement plan required by
21		this subsection (c) shall provide for the Agency to
22		procure contracts to continue offering the Illinois Solar
23		for All Program described in subsection (b) of Section
24		1-56 of this Act, and the contracts approved by the
25		Commission shall be executed by the utilities that are
26		subject to this subsection (c). The long-term renewable

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1		resources procurement plan shall allocate up to
2		$50,000,000 per delivery year to fund the programs, and
3		the plan shall determine the amount of funding to be
4		apportioned to the programs identified in subsection (b)
5		of Section 1-56 of this Act; provided that for the
6		delivery years beginning June 1, 2021, June 1, 2022, and
7		June 1, 2023, the long-term renewable resources
8		procurement plan may average the annual budgets over a
9		3-year period to account for program ramp-up. For the
10		delivery years beginning June 1, 2021, June 1, 2024, June
11		1, 2027, and June 1, 2030 and additional $10,000,000 shall
12		be provided to the Department of Commerce and Economic
13		Opportunity to implement the workforce development
14		programs and reporting as outlined in Section 16-108.12 of
15		the Public Utilities Act. In making the determinations
16		required under this subparagraph (O), the Commission shall
17		consider the experience and performance under the programs
18		and any evaluation reports. The Commission shall also
19		provide for an independent evaluation of those programs on
20		a periodic basis that are funded under this subparagraph
21		(O).
22		(P) All programs and procurements under this
23		subsection (c) shall be designed to encourage
24		participating projects to use a diverse and equitable
25		workforce and a diverse set of contractors, including
26		minority-owned businesses, disadvantaged businesses,

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1		trade unions, graduates of any workforce training programs
2		administered under this Act, and small businesses.
3		The Agency shall develop a method to optimize
4		procurement of renewable energy credits from proposed
5		utility-scale projects that are located in communities
6		eligible to receive Energy Transition Community Grants
7		pursuant to Section 10-20 of the Energy Community
8		Reinvestment Act. If this requirement conflicts with other
9		provisions of law or the Agency determines that full
10		compliance with the requirements of this subparagraph (P)
11		would be unreasonably costly or administratively
12		impractical, the Agency is to propose alternative
13		approaches to achieve development of renewable energy
14		resources in communities eligible to receive Energy
15		Transition Community Grants pursuant to Section 10-20 of
16		the Energy Community Reinvestment Act or seek an exemption
17		from this requirement from the Commission.
18		(Q) Each facility listed in subitems (i) through (ix)
19		of item (1) of this subparagraph (Q) for which a renewable
20		energy credit delivery contract is signed after the
21		effective date of this amendatory Act of the 102nd General
22		Assembly is subject to the following requirements through
23		the Agency's long-term renewable resources procurement
24		plan:
25		(1) Each facility shall be subject to the
26		prevailing wage requirements included in the

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1		Prevailing Wage Act. The Agency shall require
2		verification that all construction performed on the
3		facility by the renewable energy credit delivery
4		contract holder, its contractors, or its
5		subcontractors relating to construction of the
6		facility is performed by construction employees
7		receiving an amount for that work equal to or greater
8		than the general prevailing rate, as that term is
9		defined in Section 2 3 of the Prevailing Wage Act. For
10		purposes of this item (1), "house of worship" means
11		property that is both (1) used exclusively by a
12		religious society or body of persons as a place for
13		religious exercise or religious worship and (2)
14		recognized as exempt from taxation pursuant to Section
15		15-40 of the Property Tax Code. This item (1) shall
16		apply to any of the following:
17		(i) all new utility-scale wind projects;
18		(ii) all new utility-scale photovoltaic
19		projects and repowered wind projects;
20		(iii) all new brownfield photovoltaic
21		projects;
22		(iv) all new photovoltaic community renewable
23		energy facilities that qualify for item (iii) of
24		subparagraph (K) of this paragraph (1);
25		(v) all new community driven community
26		photovoltaic projects that qualify for item (v) of

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1		subparagraph (K) of this paragraph (1);
2		(vi) all new photovoltaic projects on public
3		school land that qualify for item (iv) of
4		subparagraph (K) of this paragraph (1);
5		(vii) all new photovoltaic distributed
6		renewable energy generation devices that (1)
7		qualify for item (i) of subparagraph (K) of this
8		paragraph (1); (2) are not projects that serve
9		single-family or multi-family residential
10		buildings; and (3) are not houses of worship where
11		the aggregate capacity including colocated
12		collocated projects would not exceed 100
13		kilowatts;
14		(viii) all new photovoltaic distributed
15		renewable energy generation devices that (1)
16		qualify for item (ii) of subparagraph (K) of this
17		paragraph (1); (2) are not projects that serve
18		single-family or multi-family residential
19		buildings; and (3) are not houses of worship where
20		the aggregate capacity including colocated
21		collocated projects would not exceed 100
22		kilowatts;
23		(ix) all new, modernized, or retooled
24		hydropower facilities;
25		(x) all new geothermal heating and cooling
26		systems awarded through the Geothermal Homes and

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1		Businesses Program under subparagraph (S) of this
2		paragraph (1) that do not serve (1) single-family
3		residential buildings, (2) multi-family
4		residential buildings with aggregate geothermal
5		system tonnage, including colocated projects, of
6		no more than 29 tons, or (3) houses of worship with
7		aggregate geothermal system tonnage, including
8		colocated projects, of no more than 29 tons.
9		(2) Renewable energy credits procured from new
10		utility-scale wind projects, new utility-scale solar
11		projects, new brownfield solar projects, repowered
12		wind projects, and retooled hydropower facilities
13		pursuant to Agency procurement events occurring after
14		the effective date of this amendatory Act of the 102nd
15		General Assembly and photovoltaic community renewable
16		generation projects where the aggregate capacity,
17		including colocated projects, exceeds 3,000 kilowatts
18		pursuant to a renewable energy credit delivery
19		contract approved by the Illinois Commerce Commission
20		under the Adjustable Block Program after the effective
21		date of this amendatory Act of the 104th General
22		Assembly must be from facilities built by general
23		contractors that must enter into a project labor
24		agreement, as defined by this Act, prior to
25		construction. Photovoltaic community renewable
26		generation projects on a program waitlist as of the

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1		effective date of this amendatory Act of the 104th
2		General Assembly awarded capacity for the program year
3		commencing June 1, 2026 or any program year thereafter
4		shall not be exempt from the project labor agreement
5		requirements of this item (2). The project labor
6		agreement shall be filed with the Director in
7		accordance with procedures established by the Agency
8		through its long-term renewable resources procurement
9		plan. Any information submitted to the Agency in this
10		item (2) shall be considered commercially sensitive
11		information. At a minimum, the project labor agreement
12		must provide the names, addresses, and occupations of
13		the owner of the plant and the individuals
14		representing the labor organization employees
15		participating in the project labor agreement
16		consistent with the Project Labor Agreements Act. The
17		agreement must also specify the terms and conditions
18		as defined by this Act.
19		(2.5) Energy storage credits procured from battery
20		storage projects pursuant to Agency procurement events
21		and additional energy storage resources procured in
22		accordance with subparagraph (B) of paragraph (3) of
23		subsection (d-20) of this Section pursuant to Agency
24		procurement events occurring after the effective date
25		of this amendatory Act of the 104th General Assembly
26		must be from facilities built by general contractors

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1		that must enter into a project labor agreement prior
2		to construction. The project labor agreement shall be
3		filed with the Director in accordance with procedures
4		established by the Agency through its long-term
5		renewable resources procurement plan. Any information
6		submitted to the Agency pursuant to this item (2.5)
7		shall be considered commercially sensitive
8		information. At a minimum, the project labor agreement
9		must provide the names, addresses, and occupations of
10		the owner of the plant and the individuals
11		representing the labor organization employees
12		participating in the project labor agreement
13		consistent with the Project Labor Agreements Act. The
14		agreement must also specify the terms and conditions,
15		as defined by this Act.
16		(3) It is the intent of this Section to ensure that
17		economic development occurs across Illinois
18		communities, that emerging businesses may grow, and
19		that there is improved access to the clean energy
20		economy by persons who have greater economic burdens
21		to success. The Agency shall take into consideration
22		the unique cost of compliance of this subparagraph (Q)
23		that might be borne by equity eligible contractors,
24		shall include such costs when determining the price of
25		renewable energy credits in the Adjustable Block
26		program and the Geothermal Homes and Businesses

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1		Program, and shall take such costs into consideration
2		in a nondiscriminatory manner when comparing bids for
3		competitive procurements. The Agency shall consider
4		costs associated with compliance whether in the
5		development, financing, or construction of projects.
6		The Agency shall periodically review the assumptions
7		in these costs and may adjust prices, in compliance
8		with subparagraph (M) of this paragraph (1).
9		(R) In its long-term renewable resources procurement
10		plan, the Agency shall establish a self-direct renewable
11		portfolio standard compliance program for eligible
12		self-direct customers that purchase renewable energy
13		credits from utility-scale wind and solar projects through
14		long-term agreements for purchase of renewable energy
15		credits as described in this Section. Such long-term
16		agreements may include the purchase of energy or other
17		products on a physical or financial basis and may involve
18		an alternative retail electric supplier as defined in
19		Section 16-102 of the Public Utilities Act. This program
20		shall take effect in the delivery year commencing June 1,
21		2023.
22		(1) For the purposes of this subparagraph:
23		"Eligible self-direct customer" means any retail
24		customers of an electric utility that serves 3,000,000
25		or more retail customers in the State and whose total
26		highest 30-minute demand was more than 10,000

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1		kilowatts, or any retail customers of an electric
2		utility that serves less than 3,000,000 retail
3		customers but more than 500,000 retail customers in
4		the State and whose total highest 15-minute demand was
5		more than 10,000 kilowatts.
6		"Retail customer" has the meaning set forth in
7		Section 16-102 of the Public Utilities Act and
8		multiple retail customer accounts under the same
9		corporate parent may aggregate their account demands
10		to meet the 10,000 kilowatt threshold. The criteria
11		for determining whether this subparagraph is
12		applicable to a retail customer shall be based on the
13		12 consecutive billing periods prior to the start of
14		the year in which the application is filed.
15		(2) For renewable energy credits to count toward
16		the self-direct renewable portfolio standard
17		compliance program, they must:
18		(i) qualify as renewable energy credits as
19		defined in Section 1-10 of this Act;
20		(ii) be sourced from one or more renewable
21		energy generating facilities that comply with the
22		geographic requirements as set forth in
23		subparagraph (I) of paragraph (1) of subsection
24		(c) as interpreted through the Agency's long-term
25		renewable resources procurement plan, or, where
26		applicable, the geographic requirements that

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1		governed utility-scale renewable energy credits at
2		the time the eligible self-direct customer entered
3		into the applicable renewable energy credit
4		purchase agreement;
5		(iii) be procured through long-term contracts
6		with term lengths of at least 10 years either
7		directly with the renewable energy generating
8		facility or through a bundled power purchase
9		agreement, a virtual power purchase agreement, an
10		agreement between the renewable generating
11		facility, an alternative retail electric supplier,
12		and the customer, or such other structure as is
13		permissible under this subparagraph (R);
14		(iv) be equivalent in volume to at least 40%
15		of the eligible self-direct customer's usage,
16		determined annually by the eligible self-direct
17		customer's usage during the previous delivery
18		year, measured to the nearest megawatt-hour;
19		(v) be retired by or on behalf of the large
20		energy customer;
21		(vi) be sourced from new utility-scale wind
22		projects or new utility-scale solar projects; and
23		(vii) if the contracts for renewable energy
24		credits are entered into after the effective date
25		of this amendatory Act of the 102nd General
26		Assembly, the new utility-scale wind projects or

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1		new utility-scale solar projects must comply with
2		the requirements established in subparagraphs (P)
3		and (Q) of paragraph (1) of this subsection (c)
4		and subsection (c-10).
5		(3) The self-direct renewable portfolio standard
6		compliance program shall be designed to allow eligible
7		self-direct customers to procure new renewable energy
8		credits from new utility-scale wind projects or new
9		utility-scale photovoltaic projects. The Agency shall
10		annually determine the amount of utility-scale
11		renewable energy credits it will include each year
12		from the self-direct renewable portfolio standard
13		compliance program, subject to receiving qualifying
14		applications. In making this determination, the Agency
15		shall evaluate publicly available analyses and studies
16		of the potential market size for utility-scale
17		renewable energy long-term purchase agreements by
18		commercial and industrial energy customers and make
19		that report publicly available. If demand for
20		participation in the self-direct renewable portfolio
21		standard compliance program exceeds availability, the
22		Agency shall ensure participation is evenly split
23		between commercial and industrial users to the extent
24		there is sufficient demand from both customer classes.
25		Each renewable energy credit procured pursuant to this
26		subparagraph (R) by a self-direct customer shall

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1		reduce the total volume of renewable energy credits
2		the Agency is otherwise required to procure from new
3		utility-scale projects pursuant to subparagraph (C) of
4		paragraph (1) of this subsection (c) on behalf of
5		contracting utilities where the eligible self-direct
6		customer is located. The self-direct customer shall
7		file an annual compliance report with the Agency
8		pursuant to terms established by the Agency through
9		its long-term renewable resources procurement plan to
10		be eligible for participation in this program.
11		Customers must provide the Agency with their most
12		recent electricity billing statements or other
13		information deemed necessary by the Agency to
14		demonstrate they are an eligible self-direct customer.
15		(4) The Commission shall approve a reduction in
16		the volumetric charges collected pursuant to Section
17		16-108 of the Public Utilities Act for approved
18		eligible self-direct customers equivalent to the
19		anticipated cost of renewable energy credit deliveries
20		under contracts for new utility-scale wind and new
21		utility-scale solar entered for each delivery year
22		after the large energy customer begins retiring
23		eligible new utility-scale utility scale renewable
24		energy credits for self-compliance. The self-direct
25		credit amount shall be determined annually and is
26		equal to the estimated portion of the cost authorized

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1		by subparagraph (E) of paragraph (1) of this
2		subsection (c) that supported the annual procurement
3		of utility-scale renewable energy credits in the prior
4		delivery year using a methodology described in the
5		long-term renewable resources procurement plan,
6		expressed on a per kilowatthour basis, and does not
7		include (i) costs associated with any contracts
8		entered into before the delivery year in which the
9		customer files the initial compliance report to be
10		eligible for participation in the self-direct program,
11		and (ii) costs associated with procuring renewable
12		energy credits through existing and future contracts
13		through the Adjustable Block Program, subsection (c-5)
14		of this Section 1-75, and the Solar for All Program.
15		The Agency shall assist the Commission in determining
16		the current and future costs. The Agency must
17		determine the self-direct credit amount for new and
18		existing eligible self-direct customers and submit
19		this to the Commission in an annual compliance filing.
20		The Commission must approve the self-direct credit
21		amount by June 1, 2023 and June 1 of each delivery year
22		thereafter.
23		(5) Customers described in this subparagraph (R)
24		shall apply, on a form developed by the Agency, to the
25		Agency to be designated as a self-direct eligible
26		customer. Once the Agency determines that a

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1		self-direct customer is eligible for participation in
2		the program, the self-direct customer will remain
3		eligible until the end of the term of the contract.
4		Thereafter, application may be made not less than 12
5		months before the filing date of the long-term
6		renewable resources procurement plan described in this
7		Act. At a minimum, such application shall contain the
8		following:
9		(i) the customer's certification that, at the
10		time of the customer's application, the customer
11		qualifies to be a self-direct eligible customer,
12		including documents demonstrating that
13		qualification;
14		(ii) the customer's certification that the
15		customer has entered into or will enter into by
16		the beginning of the applicable procurement year,
17		one or more bilateral contracts for new wind
18		projects or new photovoltaic projects, including
19		supporting documentation;
20		(iii) certification that the contract or
21		contracts for new renewable energy resources are
22		long-term contracts with term lengths of at least
23		10 years, including supporting documentation;
24		(iv) certification of the quantities of
25		renewable energy credits that the customer will
26		purchase each year under such contract or

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1		contracts, including supporting documentation;
2		(v) proof that the contract is sufficient to
3		produce renewable energy credits to be equivalent
4		in volume to at least 40% of the large energy
5		customer's usage from the previous delivery year,
6		measured to the nearest megawatt-hour; and
7		(vi) certification that the customer intends
8		to maintain the contract for the duration of the
9		length of the contract.
10		(6) If a customer receives the self-direct credit
11		but fails to properly procure and retire renewable
12		energy credits as required under this subparagraph
13		(R), the Commission, on petition from the Agency and
14		after notice and hearing, may direct such customer's
15		utility to recover the cost of the wrongfully received
16		self-direct credits plus interest through an adder to
17		charges assessed pursuant to Section 16-108 of the
18		Public Utilities Act. Self-direct customers who
19		knowingly fail to properly procure and retire
20		renewable energy credits and do not notify the Agency
21		are ineligible for continued participation in the
22		self-direct renewable portfolio standard compliance
23		program.
24		(S) Beginning with the long-term renewable resources
25		procurement plan covering program and procurement activity
26		for the delivery year beginning on June 1, 2028, any

SB0025 Enrolled - 295 - LRB104 07069 BAB 17106 b
1		long-term renewable resources procurement plan developed
2		by the Agency in accordance with subparagraph (A) of this
3		paragraph (1) shall include a Geothermal Homes and
4		Businesses Program for the procurement of geothermal
5		renewable energy credits from new geothermal heating and
6		cooling systems. The long-term renewable resources
7		procurement plan shall allocate up to $10,000,000 per
8		delivery year to fund the Program as described in this
9		subparagraph (S). The Program shall be designed to
10		stimulate the steady, predictable, and sustainable growth
11		of new geothermal heating and cooling system deployment in
12		this State and meet gaps in the marketplace. To this end,
13		the Geothermal Homes and Businesses Program shall provide
14		a transparent annual schedule of prices and quantities to
15		enable the geothermal heating and cooling market to scale
16		up and renewable energy credit prices to adjust at a
17		predictable rate over time. The prices set by the
18		Geothermal Homes and Businesses Program may be reflected
19		as a set value or as the product of a formula.
20		(i) The Geothermal Homes and Businesses Program
21		shall allocate blocks of renewable energy credits as
22		follows:
23		(1) The Agency may create categories for the
24		Program based on structure features and use cases,
25		including categories based on the nature and size
26		of the Program's projects, customers, communities

SB0025 Enrolled - 296 - LRB104 07069 BAB 17106 b
1		in which a project is located, and other
2		attributes, defined at the discretion of the
3		Agency through its long-term plan.
4		(2) The Agency shall propose an initial single
5		annual block for each Program delivery year for
6		each category it creates through the delivery year
7		beginning on June 1, 2035. The Program shall
8		include the following for eligible projects for
9		each delivery year: (I) a block of geothermal
10		renewable energy credit volumes; (II) a price for
11		renewable energy credits from geothermal heating
12		and cooling systems within the identified block;
13		and (III) the terms and conditions for securing a
14		spot on a waitlist once the block is fully
15		committed or reserved. The Agency may periodically
16		review its prior decisions establishing the amount
17		of geothermal renewable energy credit volumes in
18		each annual block and the purchase price for each
19		block and may propose, on an expedited basis,
20		changes to the previously set values, including,
21		but not limited to, redistributing the amounts and
22		the available funds as necessary and appropriate,
23		subject to Commission approval. The Agency may
24		define different block sizes, purchase prices, or
25		other distinct terms and conditions for projects
26		located in different utility service territories

SB0025 Enrolled - 297 - LRB104 07069 BAB 17106 b
1		if the Agency deems it necessary.
2		(3) The Agency may develop an intra-year and
3		year-to-year waitlist and block reservation policy
4		that balances market certainty, program
5		availability, and expedient project deployment.
6		(4) For the program year beginning on June 1,
7		2028, at least 33% of each annual block shall be
8		available to be reserved for systems that are
9		residential, as defined by the Agency. The Agency
10		shall endeavor to ensure at least 40% of each
11		annual block is available to be reserved by
12		systems located in Equity Investment Eligible
13		Communities. At least 10% of all annual blocks
14		shall be available to be reserved by systems from
15		applicants that are equity eligible contractors,
16		and the Agency shall propose to increase the
17		percentage of systems from applicants that are
18		equity eligible contractors over time to 40% based
19		on factors that include, but are not limited to,
20		the number of equity eligible contractors and the
21		volume used under this clause (4) in previous
22		delivery years. For long-term renewable resources
23		procurement plans developed thereafter, the Agency
24		may propose adjustments to the minimum percentages
25		based on developer interest, market interest and
26		availability, and other factors.

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1		(5) The Agency shall establish Program
2		eligibility requirements that ensure that systems
3		that enter the Program are sufficiently mature
4		enough to indicate a demonstrable path to
5		completion and other terms, conditions, and
6		requirements for the program, including vendor
7		registration and approval, sales and marketing
8		requirements, and other consumer protection
9		requirements as the Agency deems necessary.
10		(6) The Program shall be designed to ensure
11		that geothermal renewable energy credits are
12		procured from projects in diverse locations and
13		are not procured from projects that are
14		concentrated in a few regional areas.
15		(7) The Agency, through its long-term
16		renewable resources procurement plan, may
17		implement solutions to maintain stable and
18		consistent REC offerings to avoid gaps in
19		availability during a delivery year, including,
20		but not limited to, creating a floating block of
21		REC capacity in a given delivery year.
22		(ii) Energy derived from a geothermal heating and
23		cooling system shall be eligible for inclusion in
24		meeting the requirements of the Program. Geothermal
25		renewable energy credits shall be expressed in
26		megawatt-hour units. To make this calculation, the

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1		Agency (1) shall identify an appropriate formula
2		supported by a geothermal industry trade organization,
3		a national laboratory, or another data-backed and
4		verifiable methodology, (2) may propose adjustments to
5		any formulas for its proposed renewable energy credit
6		calculation methodology, and (3) may reflect
7		calculation methodologies already in use for other
8		State renewable portfolio standards, if applicable and
9		appropriate. The Agency shall determine the form and
10		manner in which the renewable energy credits are
11		verified and retired, in accordance with national best
12		practices.
13		Geothermal renewable energy credits retired by
14		obligated utilities for compliance with the Program
15		are only valid for compliance if those geothermal
16		renewable energy credits have not been previously
17		retired by another entity that is not the obligated
18		utility on any tracking system, carbon registry, or
19		other accounting mechanism at any time. Additionally,
20		geothermal renewable energy credits retired by
21		obligated utilities for compliance with the Program
22		shall only be valid for compliance if those geothermal
23		renewable energy credits have not been used to
24		substantiate a public emissions or energy usage claim
25		by any other another entity that is not the obligated
26		utility, of any type and at any time, whether or not

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1		the geothermal renewable energy credits were actually
2		retired on a tracking system, registry, or other
3		accounting mechanism at the time of the public
4		emissions-based claim. Geothermal renewable energy
5		credits generated for compliance with the Program
6		shall be valid only if retired once, and claimed once,
7		by the obligated utility.
8		In order to promote the competitive development of
9		geothermal heating and cooling systems in furtherance
10		of this State's interest in the health, safety, and
11		welfare of its residents, renewable energy credits
12		from geothermal heating and cooling systems shall not
13		be eligible for purchase and retirement under this Act
14		if the credits are sourced from a geothermal heating
15		and cooling system for which costs are being recovered
16		on or after the effective date of this amendatory Act
17		of the 104th General Assembly through rates regulated
18		by this State or any other state.
19		(iii) The Agency shall establish Program
20		requirements and minimum contract terms to ensure that
21		projects are properly installed and that projects
22		operate to the level of expected benefits. The
23		contract terms shall include, but are not limited to,
24		the following:
25		(1) The capital that is not advanced shall be
26		disbursed upon a schedule determined by the

SB0025 Enrolled - 301 - LRB104 07069 BAB 17106 b
1		Agency, based on the total contracted fulfillment
2		over the delivery term, not to exceed, during each
3		delivery year, the contract price multiplied by
4		the estimated annual renewable energy credit
5		generation amount. Payment structures shall
6		include provisions that provide portions of the
7		renewable energy credit delivery contract value
8		upon energization, including no less than 40% of
9		the contract value for residential projects, based
10		on the estimated renewable energy credit
11		production during the contract term.
12		(2) For renewable energy credits that qualify
13		and are procured under the Program, the delivery
14		contract length shall be 15 years.
15		(3) For contracts that are paid upon the
16		delivery of renewable energy credits, if
17		generation of renewable energy credits from
18		geothermal heating and cooling systems during a
19		delivery year exceeds the estimated annual
20		generation amount, the excess of such renewable
21		energy credits shall be carried forward to future
22		delivery years and shall not expire during the
23		delivery term. If the renewable energy credit
24		generation during a delivery year, including any
25		carried forward excess renewable energy credits,
26		is less than the estimated annual generation

SB0025 Enrolled - 302 - LRB104 07069 BAB 17106 b
1		amount, payments during the delivery year shall
2		not exceed the quantity generated plus the
3		quantity carried forward multiplied by the
4		contract price. The electric utility shall receive
5		all renewable energy credits generated by the
6		project during the first 15 years of operation,
7		and retire all renewable energy credits paid for
8		under this clause (3) and return at the end of the
9		delivery term all geothermal renewable energy
10		credits that were not paid for. Renewable energy
11		credits generated by the project thereafter shall
12		not be transferred under the renewable energy
13		credit delivery contract with the counterparty
14		electric utility.
15		(4) For renewable energy contracts for any
16		type of community, shared, or similar geothermal
17		heating and cooling system that operates using a
18		subscription model and for which subscriptions are
19		a basis for contractual payments, subscription of
20		90% of total renewable energy credit volumes or
21		greater shall be deemed to be fully subscribed.
22		(5) Beginning with the long-term renewable
23		resources procurement plan covering the delivery
24		year beginning on June 1, 2030, the Agency may
25		propose a payment structure for Program contracts
26		upon a demonstration of qualification or need

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1		under criteria established by the Agency that is
2		focused on supporting the small and emerging
3		businesses and the businesses that most acutely
4		face barriers to capital access. Successful
5		applicant firms shall have advanced capital
6		disbursed before renewable energy credits are
7		first generated. The maximum amount or percentage
8		of capital advanced shall be included in the
9		long-term renewable resources procurement plan,
10		and any amount actually advanced shall be designed
11		to overcome the barriers in access to capital that
12		are faced by an applicant through that applicant's
13		demonstration of need. The amount or percentage of
14		advanced capital may vary by year, or inter-year,
15		by structure category, block, and other factors as
16		deemed applicable by the Agency and by an
17		applicant's demonstration of need. Contracts
18		featuring capital advanced prior to system
19		operation shall feature provisions to ensure both
20		the successful development of applicant projects
21		and the delivery of renewable energy credits for
22		the full term of the contract, including ongoing
23		collateral requirements and other provisions
24		deemed necessary by the Agency. The percentage or
25		amount of capital advanced prior to system
26		operation shall not increase the overall contract

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1		value.
2		(6) Each contract shall include provisions to
3		ensure the delivery of the estimated quantity of
4		geothermal renewable energy credits, including a
5		requirement of performance assurance in an amount
6		deemed appropriate by the Agency.
7		(7) An obligated utility shall be the
8		counterparty to the contracts executed under this
9		subparagraph (S) that are approved by the
10		Commission. No contract shall be executed for an
11		amount that is less than one geothermal renewable
12		energy credit per year.
13		(8) Nothing in this subparagraph (S) shall
14		require the utility to advance any payment or pay
15		any amounts that exceed the actual amount of
16		revenues anticipated to be collected by the
17		utility inclusive of eligible funds collected in
18		prior years and alternative compliance payments
19		for use by the utility.
20		(9) Contracts may be assignable, but only to
21		entities first deemed by the Agency to have met
22		Program terms and requirements applicable to
23		direct Program participation. In developing
24		contracts for the delivery of renewable energy
25		credits from geothermal heating and cooling
26		systems, the Agency may establish fees applicable

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1		to each contract assignment.
2		(10) If, at any time, approved applications
3		for the Program exceed funds collected by the
4		electric utility or would cause the Agency to
5		exceed the limitation on the amount of renewable
6		energy resources that may be procured, then the
7		Agency may consider future uncommitted funds to be
8		reserved for these contracts on a first-come,
9		first-served basis.
10		(iv) In order to advance priority access to the
11		clean energy economy for businesses and workers from
12		communities that have been excluded from economic
13		opportunities in the energy sector, been subject to
14		disproportionate levels of pollution, and
15		disproportionately experienced negative public health
16		outcomes, the Agency shall apply its equity
17		accountability system and minimum equity standards
18		established under subsections (c-10), (c-15), (c-20),
19		(c-25), and (c-30) to geothermal heating and cooling
20		system renewable energy credit procurement and
21		programs and may include any proposed modifications to
22		the equity accountability system and minimum equity
23		standards that may be warranted with respect to
24		geothermal heating and cooling systems in its plan
25		submission to the Commission under Section 16-111.5 of
26		the Public Utilities Act.

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1		(v) Projects shall be developed in compliance with
2		the prevailing wage and project labor agreement
3		requirements, as applicable, for renewable energy
4		projects in subparagraph (Q) of paragraph (1) of
5		subsection (c). Projects approved under this Program
6		are subject to the prevailing wage requirements
7		outlined in subitem (x) of item (1) of subparagraph
8		(Q) of paragraph (1) of this subsection (c). Renewable
9		energy credits for any single geothermal heating and
10		cooling project that is 142 tons or larger and is
11		procured under this Program after the effective date
12		of this amendatory Act of the 104th General Assembly
13		shall only be eligible if the associated project was
14		built by general contractors who entered into a
15		project labor agreement prior to construction. The
16		project labor agreement shall be filed with the
17		Director in accordance with procedures established by
18		the Agency through its long-term renewable resources
19		procurement plan. The project labor agreement shall
20		provide the names, addresses, and occupations of the
21		owner of the plant and the individuals representing
22		the labor organization employees that participate in
23		the project labor agreement. The project labor
24		agreement shall also specify terms and conditions as
25		provided in this Act.
26		(vi) The Agency shall strive to minimize

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1		administrative expenses in the implementation of the
2		Program. The Agency may use any existing program
3		administrator and any applicable subcontractors to
4		develop, administer, implement, operate, and evaluate
5		the Program.
6		(T) Renewable energy credits procured under Agency
7		procurements or programs for community solar projects with
8		more than 3 megawatts in nameplate capacity must be
9		procured from facilities built by general contractors
10		that, prior to construction, enter into a project labor
11		agreement, as defined by this Act, subject to the
12		following requirements and limitations:
13		(i) The project labor agreement shall be filed
14		with the Director in accordance with procedures
15		established by the Agency through its long-term
16		renewable resources procurement plan. Any information
17		submitted to the Agency under this item (i) shall be
18		considered commercially sensitive information.
19		(ii) At a minimum, the project labor agreement
20		must provide the names, addresses, and occupations of
21		the owner of the project and any individuals
22		representing the labor organization of the employees
23		participating in the project labor agreement
24		consistent with the Project Labor Agreements Act. The
25		project labor agreement must also meet the terms and
26		conditions, as set forth in this Act.

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1		(iii) It is the intent of this Section to ensure
2		that economic development occurs across communities in
3		this State, that emerging businesses may grow, and
4		that there is improved access to the clean energy
5		economy by persons who have greater economic burdens
6		to success. The Agency shall take into consideration
7		the unique cost of compliance of this subparagraph (T)
8		that may be borne by equity eligible contractors and
9		shall include those costs when determining the price
10		of renewable energy credits in the Adjustable Block
11		program. The Agency shall consider costs associated
12		with compliance, including in the development,
13		financing, or construction of projects. The Agency
14		shall periodically review the assumptions in these
15		costs and may adjust prices in compliance with
16		subparagraph (M) of this paragraph (1).
17		(2) (Blank).
18		(3) (Blank).
19		(4) The electric utility shall retire all renewable
20		energy credits used to comply with the standard.
21		(5) Beginning with the 2010 delivery year and ending
22		June 1, 2017, an electric utility subject to this
23		subsection (c) shall apply the lesser of the maximum
24		alternative compliance payment rate or the most recent
25		estimated alternative compliance payment rate for its
26		service territory for the corresponding compliance period,

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1		established pursuant to subsection (d) of Section 16-115D
2		of the Public Utilities Act to its retail customers that
3		take service pursuant to the electric utility's hourly
4		pricing tariff or tariffs. The electric utility shall
5		retain all amounts collected as a result of the
6		application of the alternative compliance payment rate or
7		rates to such customers, and, beginning in 2011, the
8		utility shall include in the information provided under
9		item (1) of subsection (d) of Section 16-111.5 of the
10		Public Utilities Act the amounts collected under the
11		alternative compliance payment rate or rates for the prior
12		year ending May 31. Notwithstanding any limitation on the
13		procurement of renewable energy resources imposed by item
14		(2) of this subsection (c), the Agency shall increase its
15		spending on the purchase of renewable energy resources to
16		be procured by the electric utility for the next plan year
17		by an amount equal to the amounts collected by the utility
18		under the alternative compliance payment rate or rates in
19		the prior year ending May 31.
20		(6) The electric utility shall be entitled to recover
21		all of its costs associated with the procurement of
22		renewable energy credits under plans approved under this
23		Section and Section 16-111.5 of the Public Utilities Act.
24		These costs shall include associated reasonable expenses
25		for implementing the procurement programs, including, but
26		not limited to, the costs of administering and evaluating

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1		the Adjustable Block program and the Geothermal Homes and
2		Businesses Program, through an automatic adjustment clause
3		tariff in accordance with subsection (k) of Section 16-108
4		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
24		renewable energy facilities installed at or adjacent to the
25		sites of electric generating facilities that burn or burned
26		coal as their primary fuel source.

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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

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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

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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

SB0025 Enrolled - 315 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 316 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 317 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 318 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 319 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 320 - LRB104 07069 BAB 17106 b
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.

SB0025 Enrolled - 322 - LRB104 07069 BAB 17106 b
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

SB0025 Enrolled - 323 - LRB104 07069 BAB 17106 b
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
5		this subsection (c-10) to create an equity accountability
6		system, which includes the minimum equity standards for all
7		renewable energy procurements, the equity category of the
8		Adjustable Block Program, and the equity prioritization for
9		noncompetitive procurements, that is successful in advancing
10		priority access to the clean energy economy for businesses and
11		workers from communities that have been excluded from economic
12		opportunities in the energy sector, have been subject to
13		disproportionate levels of pollution, and have
14		disproportionately experienced negative public health
15		outcomes. Further, it is the purpose of this subsection to
16		ensure that this equity accountability system is successful in
17		advancing equity across Illinois by providing access to the
18		clean energy economy for businesses and workers from
19		communities that have been historically excluded from economic
20		opportunities in the energy sector, have been subject to
21		disproportionate levels of pollution, and have
22		disproportionately experienced negative public health
23		outcomes.
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		As part of the reporting requirement under this
9		subparagraph (5), the Agency shall collect and report
10		information about the use of equity eligible contractors
11		and equity eligible persons, as well as Minimum Equity
12		Standard compliance and waiver usage on the Adjustable
13		Block program and utility-scale projects subject to
14		project labor agreements. The Agency shall note any
15		instances of the projects being unable to meet or
16		requiring a waiver to meet Minimum Equity Standard
17		requirements and the location of those projects.
18		On an annual basis, the Agency shall submit a written
19		summary of its findings on an annual basis to the General
20		Assembly and the Governor and shall make the report and
21		summary available on the Agency's website.
22		(6) The Agency shall keep confidential all information
23		and communication that provides private or personal
24		information.
25		(7) Modifications to the equity accountability system.
26		As part of the update of the long-term renewable resources

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1		procurement plan to be initiated in 2023, or sooner if the
2		Agency deems necessary, the Agency shall determine the
3		extent to which the equity accountability system described
4		in this subsection (c-10) has advanced the goals of this
5		amendatory Act of the 102nd General Assembly, including
6		through the inclusion of equity eligible persons and
7		equity eligible contractors in renewable energy credit
8		projects. If the Agency finds that the equity
9		accountability system has failed to meet those goals to
10		its fullest potential, the Agency may revise the following
11		criteria for future Agency procurements: (A) the
12		percentage of project workforce, or other appropriate
13		workforce measure, certified as equity eligible persons or
14		equity eligible contractors; (B) definitions for equity
15		investment eligible persons and equity investment eligible
16		community; and (C) such other modifications necessary to
17		advance the goals of this amendatory Act of the 102nd
18		General Assembly effectively. Such revised criteria may
19		also establish distinct equity accountability systems for
20		different types of procurements or different regions of
21		the State if the Agency finds that doing so will further
22		the purposes of such programs. Revisions shall be
23		developed with stakeholder input, including from equity
24		eligible persons, equity eligible contractors, and
25		community-based organizations that work with such persons
26		and contractors.

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1		(c-15) Racial discrimination elimination powers and
2		process.
3		(1) Purpose. It is the purpose of this subsection to
4		empower the Agency and other State actors to remedy racial
5		discrimination in Illinois' clean energy economy as
6		effectively and expediently as possible, including through
7		the use of race-conscious remedies, such as race-conscious
8		contracting and hiring goals, as consistent with State and
9		federal law.
10		(2) Racial disparity and discrimination review
11		process.
12		(A) Within one year after awarding contracts using
13		the equity actions processes established in this
14		Section, the Agency shall publish a report evaluating
15		the effectiveness of the equity actions point criteria
16		of this Section in increasing participation of equity
17		eligible persons and equity eligible contractors. The
18		report shall disaggregate participating workers and
19		contractors by race and ethnicity. The report shall be
20		forwarded to the Governor, the General Assembly, and
21		the Illinois Commerce Commission and be made available
22		to the public.
23		(B) As soon as is practicable thereafter, the
24		Agency, in consultation with the Department of
25		Commerce and Economic Opportunity, Department of
26		Labor, and other agencies that may be relevant, shall

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1		commission and publish a disparity and availability
2		study that measures the presence and impact of
3		discrimination on minority businesses and workers in
4		Illinois' clean energy economy. The Agency may hire
5		consultants and experts to conduct the disparity and
6		availability study, with the retention of those
7		consultants and experts exempt from the requirements
8		of Section 20-10 of the Illinois Procurement Code. The
9		Illinois Power Agency shall forward a copy of its
10		findings and recommendations to the Governor, the
11		General Assembly, and the Illinois Commerce
12		Commission. If the disparity and availability study
13		establishes a strong basis in evidence that there is
14		discrimination in Illinois' clean energy economy, the
15		Agency, Department of Commerce and Economic
16		Opportunity, Department of Labor, Department of
17		Corrections, and other appropriate agencies shall take
18		appropriate remedial actions, including race-conscious
19		remedial actions as consistent with State and federal
20		law, to effectively remedy this discrimination. Such
21		remedies may include modification of the equity
22		accountability system as described in subsection
23		(c-10).
24		(c-20) Program data collection.
25		(1) Purpose. Data collection, data analysis, and
26		reporting are critical to ensure that the benefits of the

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1		clean energy economy provided to Illinois residents and
2		businesses are equitably distributed across the State. The
3		Agency shall collect data from program applicants in order
4		to track and improve equitable distribution of benefits
5		across Illinois communities for all procurements the
6		Agency conducts. The Agency shall use this data to, among
7		other things, measure any potential impact of racial
8		discrimination on the distribution of benefits and provide
9		information necessary to correct any discrimination
10		through methods consistent with State and federal law.
11		(2) Agency collection of program data. The Agency
12		shall collect demographic and geographic data for each
13		entity awarded contracts under any Agency-administered
14		program.
15		(3) Required information to be collected. The Agency
16		shall collect the following information from applicants
17		and program participants where applicable:
18		(A) demographic information, including racial or
19		ethnic identity for real persons employed, contracted,
20		or subcontracted through the program and owners of
21		businesses or entities that apply to receive renewable
22		energy credits from the Agency;
23		(B) geographic location of the residency of real
24		persons employed, contracted, or subcontracted through
25		the program and geographic location of the
26		headquarters of the business or entity that applies to

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1		receive renewable energy credits from the Agency; and
2		(C) any other information the Agency determines is
3		necessary for the purpose of achieving the purpose of
4		this subsection.
5		(4) Publication of collected information. The Agency
6		shall publish, at least annually, information on the
7		demographics of program participants on an aggregate
8		basis.
9		(5) Nothing in this subsection shall be interpreted to
10		limit the authority of the Agency, or other agency or
11		department of the State, to require or collect demographic
12		information from applicants of other State programs.
13		(c-25) Energy Workforce Equity Database.
14		(1) The Agency, in consultation with the Department of
15		Commerce and Economic Opportunity, shall create an Energy
16		Workforce Equity Database, and may contract with a third
17		party to do so ("database program administrator"). If the
18		Department decides to contract with a third party, that
19		third party shall be exempt from the requirements of
20		Section 20-10 of the Illinois Procurement Code. The Energy
21		Workforce Equity Database shall be a searchable database
22		of suppliers, vendors, and subcontractors for clean energy
23		industries that is:
24		(A) publicly accessible;
25		(B) easy for people to find and use;
26		(C) organized by company specialty or field;

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1		(D) region-specific; and
2		(E) populated with information including, but not
3		limited to, contacts for suppliers, vendors, or
4		subcontractors who are minority and women-owned
5		business enterprise certified or who participate or
6		have participated in any of the programs described in
7		this Act.
8		(2) The Agency shall create an easily accessible,
9		public facing online tool using the database information
10		that includes, at a minimum, the following:
11		(A) a map of environmental justice and equity
12		investment eligible communities;
13		(B) job postings and recruiting opportunities;
14		(C) a means by which recruiting clean energy
15		companies can find and interact with current or former
16		participants of clean energy workforce training
17		programs;
18		(D) information on workforce training service
19		providers and training opportunities available to
20		prospective workers;
21		(E) renewable energy company diversity reporting;
22		(F) a list of equity eligible contractors with
23		their contact information, types of work performed,
24		and locations worked in;
25		(G) reporting on outcomes of the programs
26		described in the workforce programs of the Energy

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1		Transition Act, including information such as, but not
2		limited to, retention rate, graduation rate, and
3		placement rates of trainees; and
4		(H) information about the Jobs and Environmental
5		Justice Grant Program, the Clean Energy Jobs and
6		Justice Fund, and other sources of capital.
7		(3) The Agency shall ensure the database is regularly
8		updated to ensure information is current and shall
9		coordinate with the Department of Commerce and Economic
10		Opportunity to ensure that it includes information on
11		individuals and entities that are or have participated in
12		the Clean Jobs Workforce Network Program, Clean Energy
13		Contractor Incubator Program, Returning Residents Clean
14		Jobs Training Program, or Clean Energy Primes Contractor
15		Accelerator Program.
16		(c-30) Enforcement of minimum equity standards. All
17		entities seeking renewable energy credits must submit an
18		annual report to demonstrate compliance with each of the
19		equity commitments required under subsection (c-10). If the
20		Agency concludes the entity has not met or maintained its
21		minimum equity standards required under the applicable
22		subparagraphs under subsection (c-10), the Agency shall deny
23		the entity's ability to participate in procurement programs in
24		subsection (c), including by withholding approved vendor or
25		designee status. The Agency may require the entity to enter
26		into a corrective action plan. An entity that is not

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1		recertified for failing to meet required equity actions in
2		subparagraph (c-10) may reapply once they have a corrective
3		action plan and achieve compliance with the minimum equity
4		standards.
5		(d) Clean coal portfolio standard.
6		(1) The procurement plans shall include electricity
7		generated using clean coal. Each utility shall enter into
8		one or more sourcing agreements with the initial clean
9		coal facility, as provided in paragraph (3) of this
10		subsection (d), covering electricity generated by the
11		initial clean coal facility representing at least 5% of
12		each utility's total supply to serve the load of eligible
13		retail customers in 2015 and each year thereafter, as
14		described in paragraph (3) of this subsection (d), subject
15		to the limits specified in paragraph (2) of this
16		subsection (d). It is the goal of the State that by January
17		1, 2025, 25% of the electricity used in the State shall be
18		generated by cost-effective clean coal facilities. For
19		purposes of this subsection (d), "cost-effective" means
20		that the expenditures pursuant to such sourcing agreements
21		do not cause the limit stated in paragraph (2) of this
22		subsection (d) to be exceeded and do not exceed cost-based
23		benchmarks, which shall be developed to assess all
24		expenditures pursuant to such sourcing agreements covering
25		electricity generated by clean coal facilities, other than
26		the initial clean coal facility, by the procurement

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1		administrator, in consultation with the Commission staff,
2		Agency staff, and the procurement monitor and shall be
3		subject to Commission review and approval.
4		A utility party to a sourcing agreement shall
5		immediately retire any emission credits that it receives
6		in connection with the electricity covered by such
7		agreement.
8		Utilities shall maintain adequate records documenting
9		the purchases under the sourcing agreement to comply with
10		this subsection (d) and shall file an accounting with the
11		load forecast that must be filed with the Agency by July 15
12		of each year, in accordance with subsection (d) of Section
13		16-111.5 of the Public Utilities Act.
14		A utility shall be deemed to have complied with the
15		clean coal portfolio standard specified in this subsection
16		(d) if the utility enters into a sourcing agreement as
17		required by this subsection (d).
18		(2) For purposes of this subsection (d), the required
19		execution of sourcing agreements with the initial clean
20		coal facility for a particular year shall be measured as a
21		percentage of the actual amount of electricity
22		(megawatt-hours) supplied by the electric utility to
23		eligible retail customers in the planning year ending
24		immediately prior to the agreement's execution. For
25		purposes of this subsection (d), the amount paid per
26		kilowatthour means the total amount paid for electric

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1		service expressed on a per kilowatthour basis. For
2		purposes of this subsection (d), the total amount paid for
3		electric service includes without limitation amounts paid
4		for supply, transmission, distribution, surcharges and
5		add-on taxes.
6		Notwithstanding the requirements of this subsection
7		(d), the total amount paid under sourcing agreements with
8		clean coal facilities pursuant to the procurement plan for
9		any given year shall be reduced by an amount necessary to
10		limit the annual estimated average net increase due to the
11		costs of these resources included in the amounts paid by
12		eligible retail customers in connection with electric
13		service to:
14		(A) in 2010, no more than 0.5% of the amount paid
15		per kilowatthour by those customers during the year
16		ending May 31, 2009;
17		(B) in 2011, the greater of an additional 0.5% of
18		the amount paid per kilowatthour by those customers
19		during the year ending May 31, 2010 or 1% of the amount
20		paid per kilowatthour by those customers during the
21		year ending May 31, 2009;
22		(C) in 2012, the greater of an additional 0.5% of
23		the amount paid per kilowatthour by those customers
24		during the year ending May 31, 2011 or 1.5% of the
25		amount paid per kilowatthour by those customers during
26		the year ending May 31, 2009;

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1		(D) in 2013, the greater of an additional 0.5% of
2		the amount paid per kilowatthour by those customers
3		during the year ending May 31, 2012 or 2% of the amount
4		paid per kilowatthour by those customers during the
5		year ending May 31, 2009; and
6		(E) thereafter, the total amount paid under
7		sourcing agreements with clean coal facilities
8		pursuant to the procurement plan for any single year
9		shall be reduced by an amount necessary to limit the
10		estimated average net increase due to the cost of
11		these resources included in the amounts paid by
12		eligible retail customers in connection with electric
13		service to no more than the greater of (i) 2.015% of
14		the amount paid per kilowatthour by those customers
15		during the year ending May 31, 2009 or (ii) the
16		incremental amount per kilowatthour paid for these
17		resources in 2013. These requirements may be altered
18		only as provided by statute.
19		No later than June 30, 2015, the Commission shall
20		review the limitation on the total amount paid under
21		sourcing agreements, if any, with clean coal facilities
22		pursuant to this subsection (d) and report to the General
23		Assembly its findings as to whether that limitation unduly
24		constrains the amount of electricity generated by
25		cost-effective clean coal facilities that is covered by
26		sourcing agreements.

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1		(3) Initial clean coal facility. In order to promote
2		development of clean coal facilities in Illinois, each
3		electric utility subject to this Section shall execute a
4		sourcing agreement to source electricity from a proposed
5		clean coal facility in Illinois (the "initial clean coal
6		facility") that will have a nameplate capacity of at least
7		500 MW when commercial operation commences, that has a
8		final Clean Air Act permit on June 1, 2009 (the effective
9		date of Public Act 95-1027), and that will meet the
10		definition of clean coal facility in Section 1-10 of this
11		Act when commercial operation commences. The sourcing
12		agreements with this initial clean coal facility shall be
13		subject to both approval of the initial clean coal
14		facility by the General Assembly and satisfaction of the
15		requirements of paragraph (4) of this subsection (d) and
16		shall be executed within 90 days after any such approval
17		by the General Assembly. The Agency and the Commission
18		shall have authority to inspect all books and records
19		associated with the initial clean coal facility during the
20		term of such a sourcing agreement. A utility's sourcing
21		agreement for electricity produced by the initial clean
22		coal facility shall include:
23		(A) a formula contractual price (the "contract
24		price") approved pursuant to paragraph (4) of this
25		subsection (d), which shall:
26		(i) be determined using a cost of service

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1		methodology employing either a level or deferred
2		capital recovery component, based on a capital
3		structure consisting of 45% equity and 55% debt,
4		and a return on equity as may be approved by the
5		Federal Energy Regulatory Commission, which in any
6		case may not exceed the lower of 11.5% or the rate
7		of return approved by the General Assembly
8		pursuant to paragraph (4) of this subsection (d);
9		and
10		(ii) provide that all miscellaneous net
11		revenue, including but not limited to net revenue
12		from the sale of emission allowances, if any,
13		substitute natural gas, if any, grants or other
14		support provided by the State of Illinois or the
15		United States Government, firm transmission
16		rights, if any, by-products produced by the
17		facility, energy or capacity derived from the
18		facility and not covered by a sourcing agreement
19		pursuant to paragraph (3) of this subsection (d)
20		or item (5) of subsection (d) of Section 16-115 of
21		the Public Utilities Act, whether generated from
22		the synthesis gas derived from coal, from SNG, or
23		from natural gas, shall be credited against the
24		revenue requirement for this initial clean coal
25		facility;
26		(B) power purchase provisions, which shall:

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1		(i) provide that the utility party to such
2		sourcing agreement shall pay the contract price
3		for electricity delivered under such sourcing
4		agreement;
5		(ii) require delivery of electricity to the
6		regional transmission organization market of the
7		utility that is party to such sourcing agreement;
8		(iii) require the utility party to such
9		sourcing agreement to buy from the initial clean
10		coal facility in each hour an amount of energy
11		equal to all clean coal energy made available from
12		the initial clean coal facility during such hour
13		times a fraction, the numerator of which is such
14		utility's retail market sales of electricity
15		(expressed in kilowatthours sold) in the State
16		during the prior calendar month and the
17		denominator of which is the total retail market
18		sales of electricity (expressed in kilowatthours
19		sold) in the State by utilities during such prior
20		month and the sales of electricity (expressed in
21		kilowatthours sold) in the State by alternative
22		retail electric suppliers during such prior month
23		that are subject to the requirements of this
24		subsection (d) and paragraph (5) of subsection (d)
25		of Section 16-115 of the Public Utilities Act,
26		provided that the amount purchased by the utility

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1		in any year will be limited by paragraph (2) of
2		this subsection (d); and
3		(iv) be considered pre-existing contracts in
4		such utility's procurement plans for eligible
5		retail customers;
6		(C) contract for differences provisions, which
7		shall:
8		(i) require the utility party to such sourcing
9		agreement to contract with the initial clean coal
10		facility in each hour with respect to an amount of
11		energy equal to all clean coal energy made
12		available from the initial clean coal facility
13		during such hour times a fraction, the numerator
14		of which is such utility's retail market sales of
15		electricity (expressed in kilowatthours sold) in
16		the utility's service territory in the State
17		during the prior calendar month and the
18		denominator of which is the total retail market
19		sales of electricity (expressed in kilowatthours
20		sold) in the State by utilities during such prior
21		month and the sales of electricity (expressed in
22		kilowatthours sold) in the State by alternative
23		retail electric suppliers during such prior month
24		that are subject to the requirements of this
25		subsection (d) and paragraph (5) of subsection (d)
26		of Section 16-115 of the Public Utilities Act,

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1		provided that the amount paid by the utility in
2		any year will be limited by paragraph (2) of this
3		subsection (d);
4		(ii) provide that the utility's payment
5		obligation in respect of the quantity of
6		electricity determined pursuant to the preceding
7		clause (i) shall be limited to an amount equal to
8		(1) the difference between the contract price
9		determined pursuant to subparagraph (A) of
10		paragraph (3) of this subsection (d) and the
11		day-ahead price for electricity delivered to the
12		regional transmission organization market of the
13		utility that is party to such sourcing agreement
14		(or any successor delivery point at which such
15		utility's supply obligations are financially
16		settled on an hourly basis) (the "reference
17		price") on the day preceding the day on which the
18		electricity is delivered to the initial clean coal
19		facility busbar, multiplied by (2) the quantity of
20		electricity determined pursuant to the preceding
21		clause (i); and
22		(iii) not require the utility to take physical
23		delivery of the electricity produced by the
24		facility;
25		(D) general provisions, which shall:
26		(i) specify a term of no more than 30 years,

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1		commencing on the commercial operation date of the
2		facility;
3		(ii) provide that utilities shall maintain
4		adequate records documenting purchases under the
5		sourcing agreements entered into to comply with
6		this subsection (d) and shall file an accounting
7		with the load forecast that must be filed with the
8		Agency by July 15 of each year, in accordance with
9		subsection (d) of Section 16-111.5 of the Public
10		Utilities Act;
11		(iii) provide that all costs associated with
12		the initial clean coal facility will be
13		periodically reported to the Federal Energy
14		Regulatory Commission and to purchasers in
15		accordance with applicable laws governing
16		cost-based wholesale power contracts;
17		(iv) permit the Illinois Power Agency to
18		assume ownership of the initial clean coal
19		facility, without monetary consideration and
20		otherwise on reasonable terms acceptable to the
21		Agency, if the Agency so requests no less than 3
22		years prior to the end of the stated contract
23		term;
24		(v) require the owner of the initial clean
25		coal facility to provide documentation to the
26		Commission each year, starting in the facility's

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1		first year of commercial operation, accurately
2		reporting the quantity of carbon emissions from
3		the facility that have been captured and
4		sequestered and report any quantities of carbon
5		released from the site or sites at which carbon
6		emissions were sequestered in prior years, based
7		on continuous monitoring of such sites. If, in any
8		year after the first year of commercial operation,
9		the owner of the facility fails to demonstrate
10		that the initial clean coal facility captured and
11		sequestered at least 50% of the total carbon
12		emissions that the facility would otherwise emit
13		or that sequestration of emissions from prior
14		years has failed, resulting in the release of
15		carbon dioxide into the atmosphere, the owner of
16		the facility must offset excess emissions. Any
17		such carbon offsets must be permanent, additional,
18		verifiable, real, located within the State of
19		Illinois, and legally and practicably enforceable.
20		The cost of such offsets for the facility that are
21		not recoverable shall not exceed $15 million in
22		any given year. No costs of any such purchases of
23		carbon offsets may be recovered from a utility or
24		its customers. All carbon offsets purchased for
25		this purpose and any carbon emission credits
26		associated with sequestration of carbon from the

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1		facility must be permanently retired. The initial
2		clean coal facility shall not forfeit its
3		designation as a clean coal facility if the
4		facility fails to fully comply with the applicable
5		carbon sequestration requirements in any given
6		year, provided the requisite offsets are
7		purchased. However, the Attorney General, on
8		behalf of the People of the State of Illinois, may
9		specifically enforce the facility's sequestration
10		requirement and the other terms of this contract
11		provision. Compliance with the sequestration
12		requirements and offset purchase requirements
13		specified in paragraph (3) of this subsection (d)
14		shall be reviewed annually by an independent
15		expert retained by the owner of the initial clean
16		coal facility, with the advance written approval
17		of the Attorney General. The Commission may, in
18		the course of the review specified in item (vii),
19		reduce the allowable return on equity for the
20		facility if the facility willfully fails to comply
21		with the carbon capture and sequestration
22		requirements set forth in this item (v);
23		(vi) include limits on, and accordingly
24		provide for modification of, the amount the
25		utility is required to source under the sourcing
26		agreement consistent with paragraph (2) of this

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1		subsection (d);
2		(vii) require Commission review: (1) to
3		determine the justness, reasonableness, and
4		prudence of the inputs to the formula referenced
5		in subparagraphs (A)(i) through (A)(iii) of
6		paragraph (3) of this subsection (d), prior to an
7		adjustment in those inputs including, without
8		limitation, the capital structure and return on
9		equity, fuel costs, and other operations and
10		maintenance costs and (2) to approve the costs to
11		be passed through to customers under the sourcing
12		agreement by which the utility satisfies its
13		statutory obligations. Commission review shall
14		occur no less than every 3 years, regardless of
15		whether any adjustments have been proposed, and
16		shall be completed within 9 months;
17		(viii) limit the utility's obligation to such
18		amount as the utility is allowed to recover
19		through tariffs filed with the Commission,
20		provided that neither the clean coal facility nor
21		the utility waives any right to assert federal
22		pre-emption or any other argument in response to a
23		purported disallowance of recovery costs;
24		(ix) limit the utility's or alternative retail
25		electric supplier's obligation to incur any
26		liability until such time as the facility is in

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1		commercial operation and generating power and
2		energy and such power and energy is being
3		delivered to the facility busbar;
4		(x) provide that the owner or owners of the
5		initial clean coal facility, which is the
6		counterparty to such sourcing agreement, shall
7		have the right from time to time to elect whether
8		the obligations of the utility party thereto shall
9		be governed by the power purchase provisions or
10		the contract for differences provisions;
11		(xi) append documentation showing that the
12		formula rate and contract, insofar as they relate
13		to the power purchase provisions, have been
14		approved by the Federal Energy Regulatory
15		Commission pursuant to Section 205 of the Federal
16		Power Act;
17		(xii) provide that any changes to the terms of
18		the contract, insofar as such changes relate to
19		the power purchase provisions, are subject to
20		review under the public interest standard applied
21		by the Federal Energy Regulatory Commission
22		pursuant to Sections 205 and 206 of the Federal
23		Power Act; and
24		(xiii) conform with customary lender
25		requirements in power purchase agreements used as
26		the basis for financing non-utility generators.

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1		(4) Effective date of sourcing agreements with the
2		initial clean coal facility. Any proposed sourcing
3		agreement with the initial clean coal facility shall not
4		become effective unless the following reports are prepared
5		and submitted and authorizations and approvals obtained:
6		(i) Facility cost report. The owner of the initial
7		clean coal facility shall submit to the Commission,
8		the Agency, and the General Assembly a front-end
9		engineering and design study, a facility cost report,
10		method of financing (including but not limited to
11		structure and associated costs), and an operating and
12		maintenance cost quote for the facility (collectively
13		"facility cost report"), which shall be prepared in
14		accordance with the requirements of this paragraph (4)
15		of subsection (d) of this Section, and shall provide
16		the Commission and the Agency access to the work
17		papers, relied upon documents, and any other backup
18		documentation related to the facility cost report.
19		(ii) Commission report. Within 6 months following
20		receipt of the facility cost report, the Commission,
21		in consultation with the Agency, shall submit a report
22		to the General Assembly setting forth its analysis of
23		the facility cost report. Such report shall include,
24		but not be limited to, a comparison of the costs
25		associated with electricity generated by the initial
26		clean coal facility to the costs associated with

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1		electricity generated by other types of generation
2		facilities, an analysis of the rate impacts on
3		residential and small business customers over the life
4		of the sourcing agreements, and an analysis of the
5		likelihood that the initial clean coal facility will
6		commence commercial operation by and be delivering
7		power to the facility's busbar by 2016. To assist in
8		the preparation of its report, the Commission, in
9		consultation with the Agency, may hire one or more
10		experts or consultants, the costs of which shall be
11		paid for by the owner of the initial clean coal
12		facility. The Commission and Agency may begin the
13		process of selecting such experts or consultants prior
14		to receipt of the facility cost report.
15		(iii) General Assembly approval. The proposed
16		sourcing agreements shall not take effect unless,
17		based on the facility cost report and the Commission's
18		report, the General Assembly enacts authorizing
19		legislation approving (A) the projected price, stated
20		in cents per kilowatthour, to be charged for
21		electricity generated by the initial clean coal
22		facility, (B) the projected impact on residential and
23		small business customers' bills over the life of the
24		sourcing agreements, and (C) the maximum allowable
25		return on equity for the project; and
26		(iv) Commission review. If the General Assembly

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1		enacts authorizing legislation pursuant to
2		subparagraph (iii) approving a sourcing agreement, the
3		Commission shall, within 90 days of such enactment,
4		complete a review of such sourcing agreement. During
5		such time period, the Commission shall implement any
6		directive of the General Assembly, resolve any
7		disputes between the parties to the sourcing agreement
8		concerning the terms of such agreement, approve the
9		form of such agreement, and issue an order finding
10		that the sourcing agreement is prudent and reasonable.
11		The facility cost report shall be prepared as follows:
12		(A) The facility cost report shall be prepared by
13		duly licensed engineering and construction firms
14		detailing the estimated capital costs payable to one
15		or more contractors or suppliers for the engineering,
16		procurement and construction of the components
17		comprising the initial clean coal facility and the
18		estimated costs of operation and maintenance of the
19		facility. The facility cost report shall include:
20		(i) an estimate of the capital cost of the
21		core plant based on one or more front end
22		engineering and design studies for the
23		gasification island and related facilities. The
24		core plant shall include all civil, structural,
25		mechanical, electrical, control, and safety
26		systems.

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1		(ii) an estimate of the capital cost of the
2		balance of the plant, including any capital costs
3		associated with sequestration of carbon dioxide
4		emissions and all interconnects and interfaces
5		required to operate the facility, such as
6		transmission of electricity, construction or
7		backfeed power supply, pipelines to transport
8		substitute natural gas or carbon dioxide, potable
9		water supply, natural gas supply, water supply,
10		water discharge, landfill, access roads, and coal
11		delivery.
12		The quoted construction costs shall be expressed
13		in nominal dollars as of the date that the quote is
14		prepared and shall include capitalized financing costs
15		during construction, taxes, insurance, and other
16		owner's costs, and an assumed escalation in materials
17		and labor beyond the date as of which the construction
18		cost quote is expressed.
19		(B) The front end engineering and design study for
20		the gasification island and the cost study for the
21		balance of plant shall include sufficient design work
22		to permit quantification of major categories of
23		materials, commodities and labor hours, and receipt of
24		quotes from vendors of major equipment required to
25		construct and operate the clean coal facility.
26		(C) The facility cost report shall also include an

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1		operating and maintenance cost quote that will provide
2		the estimated cost of delivered fuel, personnel,
3		maintenance contracts, chemicals, catalysts,
4		consumables, spares, and other fixed and variable
5		operations and maintenance costs. The delivered fuel
6		cost estimate will be provided by a recognized third
7		party expert or experts in the fuel and transportation
8		industries. The balance of the operating and
9		maintenance cost quote, excluding delivered fuel
10		costs, will be developed based on the inputs provided
11		by duly licensed engineering and construction firms
12		performing the construction cost quote, potential
13		vendors under long-term service agreements and plant
14		operating agreements, or recognized third party plant
15		operator or operators.
16		The operating and maintenance cost quote
17		(including the cost of the front end engineering and
18		design study) shall be expressed in nominal dollars as
19		of the date that the quote is prepared and shall
20		include taxes, insurance, and other owner's costs, and
21		an assumed escalation in materials and labor beyond
22		the date as of which the operating and maintenance
23		cost quote is expressed.
24		(D) The facility cost report shall also include an
25		analysis of the initial clean coal facility's ability
26		to deliver power and energy into the applicable

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1		regional transmission organization markets and an
2		analysis of the expected capacity factor for the
3		initial clean coal facility.
4		(E) Amounts paid to third parties unrelated to the
5		owner or owners of the initial clean coal facility to
6		prepare the core plant construction cost quote,
7		including the front end engineering and design study,
8		and the operating and maintenance cost quote will be
9		reimbursed through Coal Development Bonds.
10		(5) Re-powering and retrofitting coal-fired power
11		plants previously owned by Illinois utilities to qualify
12		as clean coal facilities. During the 2009 procurement
13		planning process and thereafter, the Agency and the
14		Commission shall consider sourcing agreements covering
15		electricity generated by power plants that were previously
16		owned by Illinois utilities and that have been or will be
17		converted into clean coal facilities, as defined by
18		Section 1-10 of this Act. Pursuant to such procurement
19		planning process, the owners of such facilities may
20		propose to the Agency sourcing agreements with utilities
21		and alternative retail electric suppliers required to
22		comply with subsection (d) of this Section and item (5) of
23		subsection (d) of Section 16-115 of the Public Utilities
24		Act, covering electricity generated by such facilities. In
25		the case of sourcing agreements that are power purchase
26		agreements, the contract price for electricity sales shall

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1		be established on a cost of service basis. In the case of
2		sourcing agreements that are contracts for differences,
3		the contract price from which the reference price is
4		subtracted shall be established on a cost of service
5		basis. The Agency and the Commission may approve any such
6		utility sourcing agreements that do not exceed cost-based
7		benchmarks developed by the procurement administrator, in
8		consultation with the Commission staff, Agency staff and
9		the procurement monitor, subject to Commission review and
10		approval. The Commission shall have authority to inspect
11		all books and records associated with these clean coal
12		facilities during the term of any such contract.
13		(6) Costs incurred under this subsection (d) or
14		pursuant to a contract entered into under this subsection
15		(d) shall be deemed prudently incurred and reasonable in
16		amount and the electric utility shall be entitled to full
17		cost recovery pursuant to the tariffs filed with the
18		Commission.
19		(d-5) Zero emission standard.
20		(1) Beginning with the delivery year commencing on
21		June 1, 2017, the Agency shall, for electric utilities
22		that serve at least 100,000 retail customers in this
23		State, procure contracts with zero emission facilities
24		that are reasonably capable of generating cost-effective
25		zero emission credits in an amount approximately equal to
26		16% of the actual amount of electricity delivered by each

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1		electric utility to retail customers in the State during
2		calendar year 2014. For an electric utility serving fewer
3		than 100,000 retail customers in this State that
4		requested, under Section 16-111.5 of the Public Utilities
5		Act, that the Agency procure power and energy for all or a
6		portion of the utility's Illinois load for the delivery
7		year commencing June 1, 2016, the Agency shall procure
8		contracts with zero emission facilities that are
9		reasonably capable of generating cost-effective zero
10		emission credits in an amount approximately equal to 16%
11		of the portion of power and energy to be procured by the
12		Agency for the utility. The duration of the contracts
13		procured under this subsection (d-5) shall be for a term
14		of 10 years ending May 31, 2027. The quantity of zero
15		emission credits to be procured under the contracts shall
16		be all of the zero emission credits generated by the zero
17		emission facility in each delivery year; however, if the
18		zero emission facility is owned by more than one entity,
19		then the quantity of zero emission credits to be procured
20		under the contracts shall be the amount of zero emission
21		credits that are generated from the portion of the zero
22		emission facility that is owned by the winning supplier.
23		The 16% value identified in this paragraph (1) is the
24		average of the percentage targets in subparagraph (B) of
25		paragraph (1) of subsection (c) of this Section for the 5
26		delivery years beginning June 1, 2017.

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1		The procurement process shall be subject to the
2		following provisions:
3		(A) Those zero emission facilities that intend to
4		participate in the procurement shall submit to the
5		Agency the following eligibility information for each
6		zero emission facility on or before the date
7		established by the Agency:
8		(i) the in-service date and remaining useful
9		life of the zero emission facility;
10		(ii) the amount of power generated annually
11		for each of the years 2005 through 2015, and the
12		projected zero emission credits to be generated
13		over the remaining useful life of the zero
14		emission facility, which shall be used to
15		determine the capability of each facility;
16		(iii) the annual zero emission facility cost
17		projections, expressed on a per megawatthour
18		basis, over the next 6 delivery years, which shall
19		include the following: operation and maintenance
20		expenses; fully allocated overhead costs, which
21		shall be allocated using the methodology developed
22		by the Institute for Nuclear Power Operations;
23		fuel expenditures; non-fuel capital expenditures;
24		spent fuel expenditures; a return on working
25		capital; the cost of operational and market risks
26		that could be avoided by ceasing operation; and

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1		any other costs necessary for continued
2		operations, provided that "necessary" means, for
3		purposes of this item (iii), that the costs could
4		reasonably be avoided only by ceasing operations
5		of the zero emission facility; and
6		(iv) a commitment to continue operating, for
7		the duration of the contract or contracts executed
8		under the procurement held under this subsection
9		(d-5), the zero emission facility that produces
10		the zero emission credits to be procured in the
11		procurement.
12		The information described in item (iii) of this
13		subparagraph (A) may be submitted on a confidential
14		basis and shall be treated and maintained by the
15		Agency, the procurement administrator, and the
16		Commission as confidential and proprietary and exempt
17		from disclosure under subparagraphs (a) and (g) of
18		paragraph (1) of Section 7 of the Freedom of
19		Information Act. The Office of Attorney General shall
20		have access to, and maintain the confidentiality of,
21		such information pursuant to Section 6.5 of the
22		Attorney General Act.
23		(B) The price for each zero emission credit
24		procured under this subsection (d-5) for each delivery
25		year shall be in an amount that equals the Social Cost
26		of Carbon, expressed on a price per megawatthour

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1		basis. However, to ensure that the procurement remains
2		affordable to retail customers in this State if
3		electricity prices increase, the price in an
4		applicable delivery year shall be reduced below the
5		Social Cost of Carbon by the amount ("Price
6		Adjustment") by which the market price index for the
7		applicable delivery year exceeds the baseline market
8		price index for the consecutive 12-month period ending
9		May 31, 2016. If the Price Adjustment is greater than
10		or equal to the Social Cost of Carbon in an applicable
11		delivery year, then no payments shall be due in that
12		delivery year. The components of this calculation are
13		defined as follows:
14		(i) Social Cost of Carbon: The Social Cost of
15		Carbon is $16.50 per megawatthour, which is based
16		on the U.S. Interagency Working Group on Social
17		Cost of Carbon's price in the August 2016
18		Technical Update using a 3% discount rate,
19		adjusted for inflation for each year of the
20		program. Beginning with the delivery year
21		commencing June 1, 2023, the price per
22		megawatthour shall increase by $1 per
23		megawatthour, and continue to increase by an
24		additional $1 per megawatthour each delivery year
25		thereafter.
26		(ii) Baseline market price index: The baseline

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1		market price index for the consecutive 12-month
2		period ending May 31, 2016 is $31.40 per
3		megawatthour, which is based on the sum of (aa)
4		the average day-ahead energy price across all
5		hours of such 12-month period at the PJM
6		Interconnection LLC Northern Illinois Hub, (bb)
7		50% multiplied by the Base Residual Auction, or
8		its successor, capacity price for the rest of the
9		RTO zone group determined by PJM Interconnection
10		LLC, divided by 24 hours per day, and (cc) 50%
11		multiplied by the Planning Resource Auction, or
12		its successor, capacity price for Zone 4
13		determined by the Midcontinent Independent System
14		Operator, Inc., divided by 24 hours per day.
15		(iii) Market price index: The market price
16		index for a delivery year shall be the sum of
17		projected energy prices and projected capacity
18		prices determined as follows:
19		(aa) Projected energy prices: the
20		projected energy prices for the applicable
21		delivery year shall be calculated once for the
22		year using the forward market price for the
23		PJM Interconnection, LLC Northern Illinois
24		Hub. The forward market price shall be
25		calculated as follows: the energy forward
26		prices for each month of the applicable

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1		delivery year averaged for each trade date
2		during the calendar year immediately preceding
3		that delivery year to produce a single energy
4		forward price for the delivery year. The
5		forward market price calculation shall use
6		data published by the Intercontinental
7		Exchange, or its successor.
8		(bb) Projected capacity prices:
9		(I) For the delivery years commencing
10		June 1, 2017, June 1, 2018, and June 1,
11		2019, the projected capacity price shall
12		be equal to the sum of (1) 50% multiplied
13		by the Base Residual Auction, or its
14		successor, price for the rest of the RTO
15		zone group as determined by PJM
16		Interconnection LLC, divided by 24 hours
17		per day and, (2) 50% multiplied by the
18		resource auction price determined in the
19		resource auction administered by the
20		Midcontinent Independent System Operator,
21		Inc., in which the largest percentage of
22		load cleared for Local Resource Zone 4,
23		divided by 24 hours per day, and where
24		such price is determined by the
25		Midcontinent Independent System Operator,
26		Inc.

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1		(II) For the delivery year commencing
2		June 1, 2020, and each year thereafter,
3		the projected capacity price shall be
4		equal to the sum of (1) 50% multiplied by
5		the Base Residual Auction, or its
6		successor, price for the ComEd zone as
7		determined by PJM Interconnection LLC,
8		divided by 24 hours per day, and (2) 50%
9		multiplied by the resource auction price
10		determined in the resource auction
11		administered by the Midcontinent
12		Independent System Operator, Inc., in
13		which the largest percentage of load
14		cleared for Local Resource Zone 4, divided
15		by 24 hours per day, and where such price
16		is determined by the Midcontinent
17		Independent System Operator, Inc.
18		For purposes of this subsection (d-5):
19		"Rest of the RTO" and "ComEd Zone" shall have
20		the meaning ascribed to them by PJM
21		Interconnection, LLC.
22		"RTO" means regional transmission
23		organization.
24		(C) No later than 45 days after June 1, 2017 (the
25		effective date of Public Act 99-906), the Agency shall
26		publish its proposed zero emission standard

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1		procurement plan. The plan shall be consistent with
2		the provisions of this paragraph (1) and shall provide
3		that winning bids shall be selected based on public
4		interest criteria that include, but are not limited
5		to, minimizing carbon dioxide emissions that result
6		from electricity consumed in Illinois and minimizing
7		sulfur dioxide, nitrogen oxide, and particulate matter
8		emissions that adversely affect the citizens of this
9		State. In particular, the selection of winning bids
10		shall take into account the incremental environmental
11		benefits resulting from the procurement, such as any
12		existing environmental benefits that are preserved by
13		the procurements held under Public Act 99-906 and
14		would cease to exist if the procurements were not
15		held, including the preservation of zero emission
16		facilities. The plan shall also describe in detail how
17		each public interest factor shall be considered and
18		weighted in the bid selection process to ensure that
19		the public interest criteria are applied to the
20		procurement and given full effect.
21		For purposes of developing the plan, the Agency
22		shall consider any reports issued by a State agency,
23		board, or commission under House Resolution 1146 of
24		the 98th General Assembly and paragraph (4) of
25		subsection (d) of this Section, as well as publicly
26		available analyses and studies performed by or for

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1		regional transmission organizations that serve the
2		State and their independent market monitors.
3		Upon publishing of the zero emission standard
4		procurement plan, copies of the plan shall be posted
5		and made publicly available on the Agency's website.
6		All interested parties shall have 10 days following
7		the date of posting to provide comment to the Agency on
8		the plan. All comments shall be posted to the Agency's
9		website. Following the end of the comment period, but
10		no more than 60 days later than June 1, 2017 (the
11		effective date of Public Act 99-906), the Agency shall
12		revise the plan as necessary based on the comments
13		received and file its zero emission standard
14		procurement plan with the Commission.
15		If the Commission determines that the plan will
16		result in the procurement of cost-effective zero
17		emission credits, then the Commission shall, after
18		notice and hearing, but no later than 45 days after the
19		Agency filed the plan, approve the plan or approve
20		with modification. For purposes of this subsection
21		(d-5), "cost effective" means the projected costs of
22		procuring zero emission credits from zero emission
23		facilities do not cause the limit stated in paragraph
24		(2) of this subsection to be exceeded.
25		(C-5) As part of the Commission's review and
26		acceptance or rejection of the procurement results,

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1		the Commission shall, in its public notice of
2		successful bidders:
3		(i) identify how the winning bids satisfy the
4		public interest criteria described in subparagraph
5		(C) of this paragraph (1) of minimizing carbon
6		dioxide emissions that result from electricity
7		consumed in Illinois and minimizing sulfur
8		dioxide, nitrogen oxide, and particulate matter
9		emissions that adversely affect the citizens of
10		this State;
11		(ii) specifically address how the selection of
12		winning bids takes into account the incremental
13		environmental benefits resulting from the
14		procurement, including any existing environmental
15		benefits that are preserved by the procurements
16		held under Public Act 99-906 and would have ceased
17		to exist if the procurements had not been held,
18		such as the preservation of zero emission
19		facilities;
20		(iii) quantify the environmental benefit of
21		preserving the resources identified in item (ii)
22		of this subparagraph (C-5), including the
23		following:
24		(aa) the value of avoided greenhouse gas
25		emissions measured as the product of the zero
26		emission facilities' output over the contract

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1		term multiplied by the U.S. Environmental
2		Protection Agency eGrid subregion carbon
3		dioxide emission rate and the U.S. Interagency
4		Working Group on Social Cost of Carbon's price
5		in the August 2016 Technical Update using a 3%
6		discount rate, adjusted for inflation for each
7		delivery year; and
8		(bb) the costs of replacement with other
9		zero carbon dioxide resources, including wind
10		and photovoltaic, based upon the simple
11		average of the following:
12		(I) the price, or if there is more
13		than one price, the average of the prices,
14		paid for renewable energy credits from new
15		utility-scale wind projects in the
16		procurement events specified in item (i)
17		of subparagraph (G) of paragraph (1) of
18		subsection (c) of this Section; and
19		(II) the price, or if there is more
20		than one price, the average of the prices,
21		paid for renewable energy credits from new
22		utility-scale solar projects and
23		brownfield site photovoltaic projects in
24		the procurement events specified in item
25		(ii) of subparagraph (G) of paragraph (1)
26		of subsection (c) of this Section and,

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1		after January 1, 2015, renewable energy
2		credits from photovoltaic distributed
3		generation projects in procurement events
4		held under subsection (c) of this Section.
5		Each utility shall enter into binding contractual
6		arrangements with the winning suppliers.
7		The procurement described in this subsection
8		(d-5), including, but not limited to, the execution of
9		all contracts procured, shall be completed no later
10		than May 10, 2017. Based on the effective date of
11		Public Act 99-906, the Agency and Commission may, as
12		appropriate, modify the various dates and timelines
13		under this subparagraph and subparagraphs (C) and (D)
14		of this paragraph (1). The procurement and plan
15		approval processes required by this subsection (d-5)
16		shall be conducted in conjunction with the procurement
17		and plan approval processes required by subsection (c)
18		of this Section and Section 16-111.5 of the Public
19		Utilities Act, to the extent practicable.
20		Notwithstanding whether a procurement event is
21		conducted under Section 16-111.5 of the Public
22		Utilities Act, the Agency shall immediately initiate a
23		procurement process on June 1, 2017 (the effective
24		date of Public Act 99-906).
25		(D) Following the procurement event described in
26		this paragraph (1) and consistent with subparagraph

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1		(B) of this paragraph (1), the Agency shall calculate
2		the payments to be made under each contract for the
3		next delivery year based on the market price index for
4		that delivery year. The Agency shall publish the
5		payment calculations no later than May 25, 2017 and
6		every May 25 thereafter.
7		(E) Notwithstanding the requirements of this
8		subsection (d-5), the contracts executed under this
9		subsection (d-5) shall provide that the zero emission
10		facility may, as applicable, suspend or terminate
11		performance under the contracts in the following
12		instances:
13		(i) A zero emission facility shall be excused
14		from its performance under the contract for any
15		cause beyond the control of the resource,
16		including, but not restricted to, acts of God,
17		flood, drought, earthquake, storm, fire,
18		lightning, epidemic, war, riot, civil disturbance
19		or disobedience, labor dispute, labor or material
20		shortage, sabotage, acts of public enemy,
21		explosions, orders, regulations or restrictions
22		imposed by governmental, military, or lawfully
23		established civilian authorities, which, in any of
24		the foregoing cases, by exercise of commercially
25		reasonable efforts the zero emission facility
26		could not reasonably have been expected to avoid,

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1		and which, by the exercise of commercially
2		reasonable efforts, it has been unable to
3		overcome. In such event, the zero emission
4		facility shall be excused from performance for the
5		duration of the event, including, but not limited
6		to, delivery of zero emission credits, and no
7		payment shall be due to the zero emission facility
8		during the duration of the event.
9		(ii) A zero emission facility shall be
10		permitted to terminate the contract if legislation
11		is enacted into law by the General Assembly that
12		imposes or authorizes a new tax, special
13		assessment, or fee on the generation of
14		electricity, the ownership or leasehold of a
15		generating unit, or the privilege or occupation of
16		such generation, ownership, or leasehold of
17		generation units by a zero emission facility.
18		However, the provisions of this item (ii) do not
19		apply to any generally applicable tax, special
20		assessment or fee, or requirements imposed by
21		federal law.
22		(iii) A zero emission facility shall be
23		permitted to terminate the contract in the event
24		that the resource requires capital expenditures in
25		excess of $40,000,000 that were neither known nor
26		reasonably foreseeable at the time it executed the

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1		contract and that a prudent owner or operator of
2		such resource would not undertake.
3		(iv) A zero emission facility shall be
4		permitted to terminate the contract in the event
5		the Nuclear Regulatory Commission terminates the
6		resource's license.
7		(F) If the zero emission facility elects to
8		terminate a contract under subparagraph (E) of this
9		paragraph (1), then the Commission shall reopen the
10		docket in which the Commission approved the zero
11		emission standard procurement plan under subparagraph
12		(C) of this paragraph (1) and, after notice and
13		hearing, enter an order acknowledging the contract
14		termination election if such termination is consistent
15		with the provisions of this subsection (d-5).
16		(2) For purposes of this subsection (d-5), the amount
17		paid per kilowatthour means the total amount paid for
18		electric service expressed on a per kilowatthour basis.
19		For purposes of this subsection (d-5), the total amount
20		paid for electric service includes, without limitation,
21		amounts paid for supply, transmission, distribution,
22		surcharges, and add-on taxes.
23		Notwithstanding the requirements of this subsection
24		(d-5), the contracts executed under this subsection (d-5)
25		shall provide that the total of zero emission credits
26		procured under a procurement plan shall be subject to the

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1		limitations of this paragraph (2). For each delivery year,
2		the contractual volume receiving payments in such year
3		shall be reduced for all retail customers based on the
4		amount necessary to limit the net increase that delivery
5		year to the costs of those credits included in the amounts
6		paid by eligible retail customers in connection with
7		electric service to no more than 1.65% of the amount paid
8		per kilowatthour by eligible retail customers during the
9		year ending May 31, 2009. The result of this computation
10		shall apply to and reduce the procurement for all retail
11		customers, and all those customers shall pay the same
12		single, uniform cents per kilowatthour charge under
13		subsection (k) of Section 16-108 of the Public Utilities
14		Act. To arrive at a maximum dollar amount of zero emission
15		credits to be paid for the particular delivery year, the
16		resulting per kilowatthour amount shall be applied to the
17		actual amount of kilowatthours of electricity delivered by
18		the electric utility in the delivery year immediately
19		prior to the procurement, to all retail customers in its
20		service territory. Unpaid contractual volume for any
21		delivery year shall be paid in any subsequent delivery
22		year in which such payments can be made without exceeding
23		the amount specified in this paragraph (2). The
24		calculations required by this paragraph (2) shall be made
25		only once for each procurement plan year. Once the
26		determination as to the amount of zero emission credits to

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1		be paid is made based on the calculations set forth in this
2		paragraph (2), no subsequent rate impact determinations
3		shall be made and no adjustments to those contract amounts
4		shall be allowed. All costs incurred under those contracts
5		and in implementing this subsection (d-5) shall be
6		recovered by the electric utility as provided in this
7		Section.
8		No later than June 30, 2019, the Commission shall
9		review the limitation on the amount of zero emission
10		credits procured under this subsection (d-5) and report to
11		the General Assembly its findings as to whether that
12		limitation unduly constrains the procurement of
13		cost-effective zero emission credits.
14		(3) Six years after the execution of a contract under
15		this subsection (d-5), the Agency shall determine whether
16		the actual zero emission credit payments received by the
17		supplier over the 6-year period exceed the Average ZEC
18		Payment. In addition, at the end of the term of a contract
19		executed under this subsection (d-5), or at the time, if
20		any, a zero emission facility's contract is terminated
21		under subparagraph (E) of paragraph (1) of this subsection
22		(d-5), then the Agency shall determine whether the actual
23		zero emission credit payments received by the supplier
24		over the term of the contract exceed the Average ZEC
25		Payment, after taking into account any amounts previously
26		credited back to the utility under this paragraph (3). If

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1		the Agency determines that the actual zero emission credit
2		payments received by the supplier over the relevant period
3		exceed the Average ZEC Payment, then the supplier shall
4		credit the difference back to the utility. The amount of
5		the credit shall be remitted to the applicable electric
6		utility no later than 120 days after the Agency's
7		determination, which the utility shall reflect as a credit
8		on its retail customer bills as soon as practicable;
9		however, the credit remitted to the utility shall not
10		exceed the total amount of payments received by the
11		facility under its contract.
12		For purposes of this Section, the Average ZEC Payment
13		shall be calculated by multiplying the quantity of zero
14		emission credits delivered under the contract times the
15		average contract price. The average contract price shall
16		be determined by subtracting the amount calculated under
17		subparagraph (B) of this paragraph (3) from the amount
18		calculated under subparagraph (A) of this paragraph (3),
19		as follows:
20		(A) The average of the Social Cost of Carbon, as
21		defined in subparagraph (B) of paragraph (1) of this
22		subsection (d-5), during the term of the contract.
23		(B) The average of the market price indices, as
24		defined in subparagraph (B) of paragraph (1) of this
25		subsection (d-5), during the term of the contract,
26		minus the baseline market price index, as defined in

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1		subparagraph (B) of paragraph (1) of this subsection
2		(d-5).
3		If the subtraction yields a negative number, then the
4		Average ZEC Payment shall be zero.
5		(4) Cost-effective zero emission credits procured from
6		zero emission facilities shall satisfy the applicable
7		definitions set forth in Section 1-10 of this Act.
8		(5) The electric utility shall retire all zero
9		emission credits used to comply with the requirements of
10		this subsection (d-5).
11		(6) Electric utilities shall be entitled to recover
12		all of the costs associated with the procurement of zero
13		emission credits through an automatic adjustment clause
14		tariff in accordance with subsection (k) and (m) of
15		Section 16-108 of the Public Utilities Act, and the
16		contracts executed under this subsection (d-5) shall
17		provide that the utilities' payment obligations under such
18		contracts shall be reduced if an adjustment is required
19		under subsection (m) of Section 16-108 of the Public
20		Utilities Act.
21		(7) This subsection (d-5) shall become inoperative on
22		January 1, 2028.
23		(d-10) Nuclear Plant Assistance; carbon mitigation
24		credits.
25		(1) The General Assembly finds:
26		(A) The health, welfare, and prosperity of all

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1		Illinois citizens require that the State of Illinois act
2		to avoid and not increase carbon emissions from electric
3		generation sources while continuing to ensure affordable,
4		stable, and reliable electricity to all citizens.
5		(B) Absent immediate action by the State to preserve
6		existing carbon-free energy resources, those resources may
7		retire, and the electric generation needs of Illinois'
8		retail customers may be met instead by facilities that
9		emit significant amounts of carbon pollution and other
10		harmful air pollutants at a high social and economic cost
11		until Illinois is able to develop other forms of clean
12		energy.
13		(C) The General Assembly finds that nuclear power
14		generation is necessary for the State's transition to 100%
15		clean energy, and ensuring continued operation of nuclear
16		plants advances environmental and public health interests
17		through providing carbon-free electricity while reducing
18		the air pollution profile of the Illinois energy
19		generation fleet.
20		(D) The clean energy attributes of nuclear generation
21		facilities support the State in its efforts to achieve
22		100% clean energy.
23		(E) The State currently invests in various forms of
24		clean energy, including, but not limited to, renewable
25		energy, energy efficiency, and low-emission vehicles,
26		among others.

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1		(F) The Environmental Protection Agency commissioned
2		an independent audit which provided a detailed assessment
3		of the financial condition of the Illinois nuclear fleet
4		to evaluate its financial viability and whether the
5		environmental benefits of such resources were at risk. The
6		report identified the risk of losing the environmental
7		benefits of several specific nuclear units. The report
8		also identified that the LaSalle County Generating Station
9		will continue to operate through 2026 and therefore is not
10		eligible to participate in the carbon mitigation credit
11		program.
12		(G) Nuclear plants provide carbon-free energy, which
13		helps to avoid many health-related negative impacts for
14		Illinois residents.
15		(H) The procurement of carbon mitigation credits
16		representing the environmental benefits of carbon-free
17		generation will further the State's efforts at achieving
18		100% clean energy and decarbonizing the electricity sector
19		in a safe, reliable, and affordable manner. Further, the
20		procurement of carbon emission credits will enhance the
21		health and welfare of Illinois residents through decreased
22		reliance on more highly polluting generation.
23		(I) The General Assembly therefore finds it necessary
24		to establish carbon mitigation credits to ensure decreased
25		reliance on more carbon-intensive energy resources, for
26		transitioning to a fully decarbonized electricity sector,

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1		and to help ensure health and welfare of the State's
2		residents.
3		(2) As used in this subsection:
4		"Baseline costs" means costs used to establish a customer
5		protection cap that have been evaluated through an independent
6		audit of a carbon-free energy resource conducted by the
7		Environmental Protection Agency that evaluated projected
8		annual costs for operation and maintenance expenses; fully
9		allocated overhead costs, which shall be allocated using the
10		methodology developed by the Institute for Nuclear Power
11		Operations; fuel expenditures; nonfuel capital expenditures;
12		spent fuel expenditures; a return on working capital; the cost
13		of operational and market risks that could be avoided by
14		ceasing operation; and any other costs necessary for continued
15		operations, provided that "necessary" means, for purposes of
16		this definition, that the costs could reasonably be avoided
17		only by ceasing operations of the carbon-free energy resource.
18		"Carbon mitigation credit" means a tradable credit that
19		represents the carbon emission reduction attributes of one
20		megawatt-hour of energy produced from a carbon-free energy
21		resource.
22		"Carbon-free energy resource" means a generation facility
23		that: (1) is fueled by nuclear power; and (2) is
24		interconnected to PJM Interconnection, LLC.
25		(3) Procurement.
26		(A) Beginning with the delivery year commencing on

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1		June 1, 2022, the Agency shall, for electric utilities
2		serving at least 3,000,000 retail customers in the State,
3		seek to procure contracts for no more than approximately
4		54,500,000 cost-effective carbon mitigation credits from
5		carbon-free energy resources because such credits are
6		necessary to support current levels of carbon-free energy
7		generation and ensure the State meets its carbon dioxide
8		emissions reduction goals. The Agency shall not make a
9		partial award of a contract for carbon mitigation credits
10		covering a fractional amount of a carbon-free energy
11		resource's projected output.
12		(B) Each carbon-free energy resource that intends to
13		participate in a procurement shall be required to submit
14		to the Agency the following information for the resource
15		on or before the date established by the Agency:
16		(i) the in-service date and remaining useful life
17		of the carbon-free energy resource;
18		(ii) the amount of power generated annually for
19		each of the past 10 years, which shall be used to
20		determine the capability of each facility;
21		(iii) a commitment to be reflected in any contract
22		entered into pursuant to this subsection (d-10) to
23		continue operating the carbon-free energy resource at
24		a capacity factor of at least 88% annually on average
25		for the duration of the contract or contracts executed
26		under the procurement held under this subsection

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1		(d-10), except in an instance described in
2		subparagraph (E) of paragraph (1) of subsection (d-5)
3		of this Section or made impracticable as a result of
4		compliance with law or regulation;
5		(iv) financial need and the risk of loss of the
6		environmental benefits of such resource, which shall
7		include the following information:
8		(I) the carbon-free energy resource's cost
9		projections, expressed on a per megawatt-hour
10		basis, over the next 5 delivery years, which shall
11		include the following: operation and maintenance
12		expenses; fully allocated overhead costs, which
13		shall be allocated using the methodology developed
14		by the Institute for Nuclear Power Operations;
15		fuel expenditures; nonfuel capital expenditures;
16		spent fuel expenditures; a return on working
17		capital; the cost of operational and market risks
18		that could be avoided by ceasing operation; and
19		any other costs necessary for continued
20		operations, provided that "necessary" means, for
21		purposes of this subitem (I), that the costs could
22		reasonably be avoided only by ceasing operations
23		of the carbon-free energy resource; and
24		(II) the carbon-free energy resource's revenue
25		projections, including energy, capacity, ancillary
26		services, any other direct State support, known or

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1		anticipated federal attribute credits, known or
2		anticipated tax credits, and any other direct
3		federal support.
4		The information described in this subparagraph (B) may
5		be submitted on a confidential basis and shall be treated
6		and maintained by the Agency, the procurement
7		administrator, and the Commission as confidential and
8		proprietary and exempt from disclosure under subparagraphs
9		(a) and (g) of paragraph (1) of Section 7 of the Freedom of
10		Information Act. The Office of the Attorney General shall
11		have access to, and maintain the confidentiality of, such
12		information pursuant to Section 6.5 of the Attorney
13		General Act.
14		(C) The Agency shall solicit bids for the contracts
15		described in this subsection (d-10) from carbon-free
16		energy resources that have satisfied the requirements of
17		subparagraph (B) of this paragraph (3). The contracts
18		procured pursuant to a procurement event shall reflect,
19		and be subject to, the following terms, requirements, and
20		limitations:
21		(i) Contracts are for delivery of carbon
22		mitigation credits, and are not energy or capacity
23		sales contracts requiring physical delivery. Pursuant
24		to item (iii), contract payments shall fully deduct
25		the value of any monetized federal production tax
26		credits, credits issued pursuant to a federal clean

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1		energy standard, and other federal credits if
2		applicable.
3		(ii) Contracts for carbon mitigation credits shall
4		commence with the delivery year beginning on June 1,
5		2022 and shall be for a term of 5 delivery years
6		concluding on May 31, 2027.
7		(iii) The price per carbon mitigation credit to be
8		paid under a contract for a given delivery year shall
9		be equal to an accepted bid price less the sum of:
10		(I) one of the following energy price indices,
11		selected by the bidder at the time of the bid for
12		the term of the contract:
13		(aa) the weighted-average hourly day-ahead
14		price for the applicable delivery year at the
15		busbar of all resources procured pursuant to
16		this subsection (d-10), weighted by actual
17		production from the resources; or
18		(bb) the projected energy price for the
19		PJM Interconnection, LLC Northern Illinois Hub
20		for the applicable delivery year determined
21		according to subitem (aa) of item (iii) of
22		subparagraph (B) of paragraph (1) of
23		subsection (d-5).
24		(II) the Base Residual Auction Capacity Price
25		for the ComEd zone as determined by PJM
26		Interconnection, LLC, divided by 24 hours per day,

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1		for the applicable delivery year for the first 3
2		delivery years, and then any subsequent delivery
3		years unless the PJM Interconnection, LLC applies
4		the Minimum Offer Price Rule to participating
5		carbon-free energy resources because they supply
6		carbon mitigation credits pursuant to this Section
7		at which time, upon notice by the carbon-free
8		energy resource to the Commission and subject to
9		the Commission's confirmation, the value under
10		this subitem shall be zero, as further described
11		in the carbon mitigation credit procurement plan;
12		and
13		(III) any value of monetized federal tax
14		credits, direct payments, or similar subsidy
15		provided to the carbon-free energy resource from
16		any unit of government that is not already
17		reflected in energy prices.
18		If the price-per-megawatt-hour calculation
19		performed under item (iii) of this subparagraph (C)
20		for a given delivery year results in a net positive
21		value, then the electric utility counterparty to the
22		contract shall multiply such net value by the
23		applicable contract quantity and remit the amount to
24		the supplier.
25		To protect retail customers from retail rate
26		impacts that may arise upon the initiation of carbon

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1		policy changes, if the price-per-megawatt-hour
2		calculation performed under item (iii) of this
3		subparagraph (C) for a given delivery year results in
4		a net negative value, then the supplier counterparty
5		to the contract shall multiply such net value by the
6		applicable contract quantity and remit such amount to
7		the electric utility counterparty. The electric
8		utility shall reflect such amounts remitted by
9		suppliers as a credit on its retail customer bills as
10		soon as practicable.
11		(iv) To ensure that retail customers in Northern
12		Illinois do not pay more for carbon mitigation credits
13		than the value such credits provide, and
14		notwithstanding the provisions of this subsection
15		(d-10), the Agency shall not accept bids for contracts
16		that exceed a customer protection cap equal to the
17		baseline costs of carbon-free energy resources.
18		The baseline costs for the applicable year shall
19		be the following:
20		(I) For the delivery year beginning June 1,
21		2022, the baseline costs shall be an amount equal
22		to $30.30 per megawatt-hour.
23		(II) For the delivery year beginning June 1,
24		2023, the baseline costs shall be an amount equal
25		to $32.50 per megawatt-hour.
26		(III) For the delivery year beginning June 1,

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1		2024, the baseline costs shall be an amount equal
2		to $33.43 per megawatt-hour.
3		(IV) For the delivery year beginning June 1,
4		2025, the baseline costs shall be an amount equal
5		to $33.50 per megawatt-hour.
6		(V) For the delivery year beginning June 1,
7		2026, the baseline costs shall be an amount equal
8		to $34.50 per megawatt-hour.
9		An Environmental Protection Agency consultant
10		forecast, included in a report issued April 14, 2021,
11		projects that a carbon-free energy resource has the
12		opportunity to earn on average approximately $30.28
13		per megawatt-hour, for the sale of energy and capacity
14		during the time period between 2022 and 2027.
15		Therefore, the sale of carbon mitigation credits
16		provides the opportunity to receive an additional
17		amount per megawatt-hour in addition to the projected
18		prices for energy and capacity.
19		Although actual energy and capacity prices may
20		vary from year-to-year, the General Assembly finds
21		that this customer protection cap will help ensure
22		that the cost of carbon mitigation credits will be
23		less than its value, based upon the social cost of
24		carbon identified in the Technical Support Document
25		issued in February 2021 by the U.S. Interagency
26		Working Group on Social Cost of Greenhouse Gases and

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1		the PJM Interconnection, LLC carbon dioxide marginal
2		emission rate for 2020, and that a carbon-free energy
3		resource receiving payment for carbon mitigation
4		credits receives no more than necessary to keep those
5		units in operation.
6		(D) No later than 7 days after the effective date of
7		this amendatory Act of the 102nd General Assembly, the
8		Agency shall publish its proposed carbon mitigation credit
9		procurement plan. The Plan shall provide that winning bids
10		shall be selected by taking into consideration which
11		resources best match public interest criteria that
12		include, but are not limited to, minimizing carbon dioxide
13		emissions that result from electricity consumed in
14		Illinois and minimizing sulfur dioxide, nitrogen oxide,
15		and particulate matter emissions that adversely affect the
16		citizens of this State. The selection of winning bids
17		shall also take into account the incremental environmental
18		benefits resulting from the procurement or procurements,
19		such as any existing environmental benefits that are
20		preserved by a procurement held under this subsection
21		(d-10) and would cease to exist if the procurement were
22		not held, including the preservation of carbon-free energy
23		resources. For those bidders having the same public
24		interest criteria score, the relative ranking of such
25		bidders shall be determined by price. The Plan shall
26		describe in detail how each public interest factor shall

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1		be considered and weighted in the bid selection process to
2		ensure that the public interest criteria are applied to
3		the procurement. The Plan shall, to the extent practical
4		and permissible by federal law, ensure that successful
5		bidders make commercially reasonable efforts to apply for
6		federal tax credits, direct payments, or similar subsidy
7		programs that support carbon-free generation and for which
8		the successful bidder is eligible. Upon publishing of the
9		carbon mitigation credit procurement plan, copies of the
10		plan shall be posted and made publicly available on the
11		Agency's website. All interested parties shall have 7 days
12		following the date of posting to provide comment to the
13		Agency on the plan. All comments shall be posted to the
14		Agency's website. Following the end of the comment period,
15		but no more than 19 days later than the effective date of
16		this amendatory Act of the 102nd General Assembly, the
17		Agency shall revise the plan as necessary based on the
18		comments received and file its carbon mitigation credit
19		procurement plan with the Commission.
20		(E) If the Commission determines that the plan is
21		likely to result in the procurement of cost-effective
22		carbon mitigation credits, then the Commission shall,
23		after notice and hearing and opportunity for comment, but
24		no later than 42 days after the Agency filed the plan,
25		approve the plan or approve it with modification. For
26		purposes of this subsection (d-10), "cost-effective" means

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1		carbon mitigation credits that are procured from
2		carbon-free energy resources at prices that are within the
3		limits specified in this paragraph (3). As part of the
4		Commission's review and acceptance or rejection of the
5		procurement results, the Commission shall, in its public
6		notice of successful bidders:
7		(i) identify how the selected carbon-free energy
8		resources satisfy the public interest criteria
9		described in this paragraph (3) of minimizing carbon
10		dioxide emissions that result from electricity
11		consumed in Illinois and minimizing sulfur dioxide,
12		nitrogen oxide, and particulate matter emissions that
13		adversely affect the citizens of this State;
14		(ii) specifically address how the selection of
15		carbon-free energy resources takes into account the
16		incremental environmental benefits resulting from the
17		procurement, including any existing environmental
18		benefits that are preserved by the procurements held
19		under this amendatory Act of the 102nd General
20		Assembly and would have ceased to exist if the
21		procurements had not been held, such as the
22		preservation of carbon-free energy resources;
23		(iii) quantify the environmental benefit of
24		preserving the carbon-free energy resources procured
25		pursuant to this subsection (d-10), including the
26		following:

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1		(I) an assessment value of avoided greenhouse
2		gas emissions measured as the product of the
3		carbon-free energy resources' output over the
4		contract term, using generally accepted
5		methodologies for the valuation of avoided
6		emissions; and
7		(II) an assessment of costs of replacement
8		with other carbon-free energy resources and
9		renewable energy resources, including wind and
10		photovoltaic generation, based upon an assessment
11		of the prices paid for renewable energy credits
12		through programs and procurements conducted
13		pursuant to subsection (c) of Section 1-75 of this
14		Act, and the additional storage necessary to
15		produce the same or similar capability of matching
16		customer usage patterns.
17		(F) The procurements described in this paragraph (3),
18		including, but not limited to, the execution of all
19		contracts procured, shall be completed no later than
20		December 3, 2021. The procurement and plan approval
21		processes required by this paragraph (3) shall be
22		conducted in conjunction with the procurement and plan
23		approval processes required by Section 16-111.5 of the
24		Public Utilities Act, to the extent practicable. However,
25		the Agency and Commission may, as appropriate, modify the
26		various dates and timelines under this subparagraph and

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1		subparagraphs (D) and (E) of this paragraph (3) to meet
2		the December 3, 2021 contract execution deadline.
3		Following the completion of such procurements, and
4		consistent with this paragraph (3), the Agency shall
5		calculate the payments to be made under each contract in a
6		timely fashion.
7		(F-1) Costs incurred by the electric utility pursuant
8		to a contract authorized by this subsection (d-10) shall
9		be deemed prudently incurred and reasonable in amount, and
10		the electric utility shall be entitled to full cost
11		recovery pursuant to a tariff or tariffs filed with the
12		Commission.
13		(G) The counterparty electric utility shall retire all
14		carbon mitigation credits used to comply with the
15		requirements of this subsection (d-10).
16		(H) If a carbon-free energy resource is sold to
17		another owner, the rights, obligations, and commitments
18		under this subsection (d-10) shall continue to the
19		subsequent owner.
20		(I) This subsection (d-10) shall become inoperative on
21		January 1, 2028.
22		(d-20) Energy storage system portfolio standard.
23		(1) The General Assembly finds that the deployment of
24		energy storage systems is necessary to successfully
25		integrate high levels of renewable energy, to avoid the
26		creation and increase of carbon emissions from electric

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1		generation sources, and to ensure affordable, stable,
2		clean, reliable, and resilient electricity.
3		(2) The Agency shall develop an energy storage system
4		resources procurement plan that includes the competitive
5		procurement events, procurement programs, or both, as
6		necessary (i) to meet the goals set forth in this
7		subsection (d-20), (ii) to meet the planning requirements
8		established under Sections 16-201 and 16-202 of the Public
9		Utilities Act, (iii) to meet the clean energy policy
10		established by Public Act 102-662, and (iv) to cause
11		electric utilities serving more than 300,000 customers in
12		the State as of January 1, 2019 to contract for energy
13		storage resources. The energy storage system resources
14		procurement plan approval processes shall be conducted
15		consistent with the processes outlined in paragraph (6) of
16		subsection (b) of Section 16-111.5 of the Public Utilities
17		Act, with the initial energy storage system resources
18		procurement plan released for comment in calendar year
19		2027. The Agency shall review and may revise the energy
20		storage system resources procurement plan at least every 2
21		years. The Agency shall establish, and the Commission
22		shall approve or approve as modified, an energy storage
23		system resources procurement plan that includes:
24		(A) storage targets in addition to the initial
25		procurements specified in paragraph (3) of this
26		subsection (d-20) at levels identified through the

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1		integrated resource planning process outlined in
2		Section 16-202 of the Public Utilities Act;
3		(B) a bid selection process that is based on the
4		bid price, when compared with an equal energy storage
5		duration and interconnected to the same independent
6		system operator (ISO) or regional transmission
7		organization (RTO), and that may provide for
8		consideration of the following:
9		(i) the project's viability and ability to
10		meet or exceed operational date targets;
11		(ii) the developer's experience;
12		(iii) requirements for demonstration of
13		binding site control that are sufficient for
14		proposed energy storage facilities;
15		(iv) the availability or dependence on any
16		transmission expansion or upgrades needed; and
17		(v) other resource adequacy and reliability
18		considerations;
19		(C) consideration of the need to ensure adequate,
20		reliable, affordable, efficient, and environmentally
21		sustainable electric service at the lowest total cost
22		over time;
23		(D) proposals for the financial support of energy
24		storage systems using contract models, which may
25		include, but are not limited to, the following:
26		(i) an indexed storage credit procurement,

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1		including payments to energy storage system owners
2		or operators with any offsets and refunds for
3		potential energy and capacity revenues;
4		(ii) support for energy storage system
5		resources through contract structures that do not
6		create contractual obligations on utilities that
7		are not contingent on full and timely cost
8		recovery, that avoid negative financial impacts on
9		the utilities, and that are agreed upon by the
10		utilities; and
11		(iii) other approaches as deemed suitable by
12		the Agency and the Commission; and
13		(E) consideration that the Agency may include a
14		methodology that could prioritize procurement of
15		energy storage resources that are located in
16		communities eligible to receive Energy Transition
17		Community Grants pursuant to Section 10-20 of the
18		Energy Community Reinvestment Act.
19		In developing its procurement plan and conducting the
20		storage procurements outlined in this paragraph (2) and in
21		paragraph (3), the Agency may use the services of expert
22		consulting firms identified in paragraphs (1) and (2) of
23		subsection (a) of this Section.
24		(3) Notwithstanding whether an energy storage system
25		resources procurement plan has been approved, the
26		following provisions shall apply to the Agency's initial

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1		procurement of energy storage system resources under this
2		subsection (d-20):
3		(A) The Agency shall conduct an initial energy
4		storage procurement on or before August 26, 2026 or 90
5		days after the effective date of this amendatory Act
6		of the 104th General Assembly, whichever is earlier.
7		For the purposes of this initial energy storage
8		procurement, the Agency shall conduct a procurement
9		that results in electric utilities that served more
10		than 300,000 customers in the State as of January 1,
11		2019 contracting for at least 1,038 megawatts of
12		cost-effective stand-alone energy storage systems that
13		can achieve commercial operation on or before December
14		31, 2029 or an alternative date proposed by the Agency
15		that is no later than December 31, 2030. The
16		procurement target shall be separated for projects
17		interconnected within Midcontinent Independent System
18		Operator Local Resource Zone 4 (MISO Zone 4) and for
19		projects interconnected within the PJM
20		Interconnection, LLC ComEd Locational Deliverability
21		Area (PJM ComEd Area) as follows:
22		(i) 450 megawatts in MISO Zone 4; and
23		(ii) 588 megawatts in the PJM ComEd Area.
24		For purposes of this subsection (d-20),
25		"stand-alone" means systems that are (i) separately
26		metered by a revenue-quality meter that satisfies the

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1		requirements of the RTO; (ii) operate independently
2		without constraints or hindrances from other
3		generation units; and (iii) demonstrate the ability to
4		charge and discharge independent of any generation
5		unit output.
6		(B) The Agency shall conduct a series of
7		additional energy storage procurements that result in
8		electric utilities contracting for energy storage
9		resources in an amount of 3,000 megawatts of
10		cumulative energy storage capacity for projects
11		committed to reaching commercial operation on or
12		before December 31, 2030, or an alternative date
13		proposed by the Agency, subject to extension for a
14		delay due to interconnection of the energy storage
15		system, a delay in obtaining permits necessary to
16		build or operate the energy storage system, or other
17		circumstances at the discretion of the Agency.
18		The additional energy storage resources
19		procurements shall be conducted in calendar years 2027
20		and 2028 in a manner that ensures the quantities
21		listed in this subparagraph (B), and as updated in the
22		integrated resource plan approved by the Commission
23		pursuant to Section 16-201 of the Public Utilities
24		Act, are met in the specified timeframe. To the extent
25		the integrated resource planning process outlined in
26		Section 16-202 of the Public Utilities Act authorizes

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1		energy storage system procurement amounts above the
2		amount identified in this subparagraph (B), the Agency
3		shall conduct additional energy storage procurements
4		in 2028, 2029, 2030, and thereafter that result in
5		electric utilities contracting for energy storage
6		resources at those additional identified levels. The
7		procurements shall be conducted in a manner that
8		maximizes projects available in the MISO and PJM
9		queues, ensures the likelihood of project development
10		through the development of project maturity
11		requirements, enables sufficient competition for price
12		competitiveness, and aligns to the extent practicable
13		with regional transmission organization study phases.
14		The procurements shall select projects interconnected
15		to MISO Zone 4 and the PJM ComEd Area and shall follow
16		either (i) a similar geographic split to the ratio of
17		quantities established in subparagraph (A) of this
18		paragraph (3), (ii) an alternative geographic split
19		proposed by the Agency based on project availability
20		in advanced stages of the MISO and PJM queues, or (iii)
21		that is informed by MISO and PJM planning activities,
22		auctions, or reports that indicate capacity resource
23		shortages or impending shortages and that reflect the
24		assessments made through the processes outlined in
25		subparagraph (A) of paragraph (2). The additional
26		energy storage capacity procurements may be adjusted

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1		upward if determined necessary through the planning
2		process outlined in Section 16-201 of the Public
3		Utilities Act at times determined by the Commission.
4		(C) The initial energy storage resources
5		procurement under subparagraph (A) of this paragraph
6		(3) shall adopt a standard indexed storage credit
7		contract modeled after the contract and follow a
8		process modeled after the process included in the
9		staff report submitted to the Governor, General
10		Assembly, and Commission pursuant to subsection (g) of
11		Section 16-135 of the Public Utilities Act on May 1,
12		2025. In developing the procurement rules and
13		procurement process for the initial procurement, the
14		Agency shall provide an opportunity for comment on the
15		indexed storage credit contract included in the May 1,
16		2025 staff report and shall adopt modifications to the
17		contract consistent with the process outlined in
18		paragraph (2) of subsection (e) of Section 16-111.5 of
19		the Public Utilities Act.
20		(D) For the additional energy storage resources
21		procurements conducted in accordance with subparagraph
22		(B) of this paragraph (3), the Agency may, among other
23		considerations, consider other contract structures if
24		such contract structures and agreements do not create
25		contractual obligations on utilities that are not
26		contingent on full and timely cost recovery, avoid

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1		negative financial impacts on the utilities, and are
2		agreed upon by the participating utility.
3		(E) The initial and additional energy storage
4		resources procurements under this paragraph (3) shall
5		solicit 20-year contracts.
6		(F) The Agency shall submit its proposed selection
7		of successful bids for each procurement event pursuant
8		to paragraphs (2) and (3) to the Commission for
9		approval consistent with the processes outlined in
10		Section 16-111.5 of the Public Utilities Act to the
11		extent practicable.
12		(4) The energy storage system resources procurement
13		plans developed by the Agency may consider alternatives to
14		the initial and additional procurement terms described in
15		paragraph (3) of this subsection (d-20), including, but
16		not limited to:
17		(A) alternatives to the standard indexed storage
18		credit contract used in the initial terms described in
19		subparagraph (C) of paragraph (3) of this subsection
20		(d-20);
21		(B) energy storage systems that are not
22		stand-alone;
23		(C) proportionate allocations between MISO Zone 4
24		and the PJM ComEd Area that are not based upon load
25		share, including allocations reflecting the
26		assessments made through the processes outlined in

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1		subparagraph (A) of paragraph (2);
2		(D) contract lengths other than 20 years;
3		(E) energy storage system durations other than 4
4		hours; and
5		(F) energy storage systems connected to the
6		distribution systems of the electric utilities.
7		The Agency may propose specific timelines for energy
8		storage system resources procurements, which may differ
9		across RTO zones, that are based in part upon a
10		consideration of (i) the timing of the release of
11		interconnection cost information through both MISO and PJM
12		interconnection queue processes, (ii) factors that
13		maximize the likelihood of successful project development,
14		(iii) enabling sufficient competition for price
15		competitiveness, and (iv) aligning to the extent
16		practicable with RTO study phases.
17		(5) The Agency shall procure cost-effective energy
18		storage credits or other contract instruments intended to
19		facilitate the successful development of energy storage
20		projects. The procurement administrator shall establish
21		confidential price benchmarks based on publicly available
22		data on regional technology costs. Confidential price
23		benchmarks shall be developed by the procurement
24		administrator, in consultation with Commission staff,
25		Agency staff, and the procurement monitor, and shall be
26		subject to Commission review and approval. Price

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1		benchmarks shall reflect development costs, financing
2		costs, and related costs resulting from requirements
3		imposed through other provisions of State law. As used in
4		this paragraph (5), "cost-effective" means a bidder's bid
5		price that does not exceed confidential price benchmarks.
6		(6) All procurements under this subsection (d-20)
7		shall comply with the geographic requirements in
8		subparagraph (I) of paragraph (1) of subsection (c) of
9		Section 1-75 and shall follow the procurement processes
10		and procedures described in this Section and Section
11		16-111.5 of the Public Utilities Act, to the extent
12		practicable. The processes and procedures may be expedited
13		to accommodate the schedule established by this Section.
14		The Agency shall require all bidders to pay to the Agency a
15		nonrefundable deposit determined by the Agency and no less
16		than $10,000 per bid as practical. The Agency may also
17		assess bidder and supplier fees to cover the cost of
18		procurement events and develop collateral requirements to
19		maximize the likelihood of successful project development.
20		Bidders in the initial and additional procurements
21		described in paragraph (3) of this subsection (d-20) shall
22		also demonstrate experience in developing to commercial
23		readiness. As used in this paragraph (6), "developing to
24		commercial readiness" means having notice to proceed in
25		owning or operating energy facilities with a combined
26		nameplate capacity of at least 100 megawatts.

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1		(7) In order to advance priority access to the clean
2		energy economy for businesses and workers from communities
3		that have been excluded from economic opportunities in the
4		energy sector, have been subject to disproportionate
5		levels of pollution, and have disproportionately
6		experienced negative public health outcomes, the Agency
7		shall apply its equity accountability system and minimum
8		equity standards established under subsections (c-10),
9		(c-15), (c-20), (c-25), and (c-30) of this Section to
10		energy storage procurement and programs and may include
11		any proposed modifications to the equity accountability
12		system and minimum equity standards that may be warranted
13		with respect to energy storage resources in its plan
14		submission to the Commission under Section 16-111.5 of the
15		Public Utilities Act.
16		(8) Projects shall be developed in compliance with the
17		prevailing wage and project labor agreement requirements
18		for renewable energy projects in subparagraph (Q) of
19		paragraph (1) of subsection (c) of Section 1-75.
20		(9) An entity operating an energy storage facility
21		shall demonstrate that it has entered into a labor peace
22		agreement with a bona fide labor organization that is
23		actively engaged in representing its employees. The labor
24		peace agreement shall apply to the employees necessary for
25		the ongoing maintenance and operation of the energy
26		storage facility. The existence of a labor peace agreement

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1		shall be an ongoing material condition of an entity's
2		authorization to maintain and operate the energy storage
3		facility.
4		(10) In order to promote the competitive development
5		of energy storage systems in furtherance of the State's
6		interest in the health, safety, and welfare of its
7		residents, storage credits shall not be eligible to be
8		selected under this subsection (d-20) if the energy
9		storage resources are sourced from an energy storage
10		system whose costs were being recovered through rates
11		regulated by the State or any other state or states on or
12		after January 1, 2017. No entity shall be permitted to bid
13		unless it certifies to the Agency that it is not an
14		electric utility, as defined in Section 16-102 of the
15		Public Utilities Act, serving more than 10,000 customers
16		in the State.
17		(11) The Agency shall require, as a prerequisite to
18		payment for any storage credits, that the winning bidder
19		provide the Agency or its designee a copy of the
20		interconnection agreement under which the applicable
21		energy storage system is connected to the transmission or
22		distribution system.
23		(12) Contracts shall provide that, if the cost
24		recovery mechanism referenced in subsection (k) of Section
25		16-108 of the Public Utilities Act remains in full force
26		without amendment or the utility is otherwise authorized

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1		or entitled to full, prompt, and uninterrupted recovery of
2		its costs through any other mechanism, then such seller
3		shall be entitled to full, prompt, and uninterrupted
4		payment under the applicable contract notwithstanding the
5		application of this paragraph (12).
6		(e) The draft procurement plans are subject to public
7		comment, as required by Section 16-111.5 of the Public
8		Utilities Act.
9		(f) The Agency shall submit the final procurement plan to
10		the Commission. The Agency shall revise a procurement plan if
11		the Commission determines that it does not meet the standards
12		set forth in Section 16-111.5 of the Public Utilities Act.
13		(g) The Agency shall assess fees to each affected utility
14		to recover the costs incurred in preparation of procurement
15		plans and in the operation of programs the annual procurement
16		plan for the utility.
17		(h) The Agency shall assess fees to each bidder to recover
18		the costs incurred in connection with a competitive
19		procurement process.
20		(i) A renewable energy credit, carbon emission credit,
21		zero emission credit, or carbon mitigation credit can only be
22		used once to comply with a single portfolio or other standard
23		as set forth in subsection (c), subsection (d), or subsection
24		(d-5) of this Section, respectively. A renewable energy
25		credit, carbon emission credit, zero emission credit, or
26		carbon mitigation credit cannot be used to satisfy the

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1		requirements of more than one standard. If more than one type
2		of credit is issued for the same megawatt hour of energy, only
3		one credit can be used to satisfy the requirements of a single
4		standard. After such use, the credit must be retired together
5		with any other credits issued for the same megawatt hour of
6		energy.
7		(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24;
8		103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)
9		(20 ILCS 3855/1-125)
10		Sec. 1-125. Agency annual reports.
11		(a) By March February 15 of each year, the Agency shall
12		report annually to the Governor and the General Assembly on
13		the operations and transactions of the Agency. The annual
14		report shall include, but not be limited to, each of the
15		following:
16		(1) The average quantity, price, and term of all
17		contracts for electricity procured under the procurement
18		plans for electric utilities.
19		(2) (Blank).
20		(3) The quantity, price, and rate impact of all energy
21		efficiency and demand response measures purchased for
22		electric utilities, and any measures included in the
23		procurement plan pursuant to Section 16-111.5B of the
24		Public Utilities Act.
25		(4) The amount of power and energy produced by each

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1		Agency facility.
2		(5) The quantity of electricity supplied by each
3		Agency facility to municipal electric systems,
4		governmental aggregators, or rural electric cooperatives
5		in Illinois.
6		(6) The revenues as allocated by the Agency to each
7		facility.
8		(7) The costs as allocated by the Agency to each
9		facility.
10		(8) The accumulated depreciation for each facility.
11		(9) The status of any projects under development.
12		(10) Basic financial and operating information
13		specifically detailed for the reporting year and
14		including, but not limited to, income and expense
15		statements, balance sheets, and changes in financial
16		position, all in accordance with generally accepted
17		accounting principles, debt structure, and a summary of
18		funds on a cash basis.
19		(11) The average quantity, price, contract type and
20		term, and rate impact of all renewable resources procured
21		under the long-term renewable resources procurement plans
22		for electric utilities.
23		(12) A comparison of the costs associated with the
24		Agency's procurement of renewable energy resources to (A)
25		the Agency's costs associated with electricity generated
26		by other types of generation facilities and (B) the

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1		benefits associated with the Agency's procurement of
2		renewable energy resources.
3		(13) An analysis of the rate impacts associated with
4		the Illinois Power Agency's procurement of renewable
5		resources, including, but not limited to, any long-term
6		contracts, on the eligible retail customers of electric
7		utilities. The analysis shall include the Agency's
8		estimate of the total dollar impact that the Agency's
9		procurement of renewable resources has had on the annual
10		electricity bills of the customer classes that comprise
11		each eligible retail customer class taking service from an
12		electric utility.
13		(14) (Blank).
14		(b) In addition to reporting on the transactions and
15		operations of the Agency, the Agency shall also endeavor to
16		report on the following items through its annual report,
17		recognizing that full and accurate information may not be
18		available for certain items:
19		(1) The overall nameplate capacity amount of installed
20		and scheduled renewable energy generation capacity
21		physically located in Illinois.
22		(2) The percentage of installed and scheduled
23		renewable energy generation capacity as a share of overall
24		electricity generation capacity physically located in
25		Illinois.
26		(3) The amount of megawatt hours produced by renewable

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1		energy generation capacity physically located in Illinois
2		for the preceding delivery year.
3		(4) The percentage of megawatt hours produced by
4		renewable energy generation capacity physically located in
5		Illinois as a share of overall electricity generation from
6		facilities physically located in Illinois for the
7		preceding delivery year and as a share of retail
8		electricity sales in Illinois.
9		(5) The renewable portfolio standard expenditures made
10		pursuant to paragraph (1) of subsection (c) of Section
11		1-75 and the total scheduled and installed renewable
12		generation capacity expected to result from these
13		investments. This information shall include the total cost
14		of REC delivery contracts of the renewable portfolio
15		standard by project category, including, but not limited
16		to, renewable energy credits delivery contracts entered
17		into pursuant to subparagraphs (C), (G), (K), and (R) of
18		paragraph (1) of subsection (c) Section 1-75. The Agency
19		shall also report on the total amount of customer load
20		featuring renewable portfolio standard compliance
21		obligations scheduled to be met by self-direct customers
22		pursuant to subparagraph (R) of paragraph (1) of
23		subsection (c) of Section 1-75, as well as the minimum
24		annual quantities of renewable energy credits scheduled to
25		be retired by those customers and amount of installed
26		renewable energy generating capacity used to meet the

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1		requirements of subparagraph (R) of paragraph (1) of
2		subsection (c) of Section 1-75.
3		The Agency may seek assistance from the Illinois Commerce
4		Commission in developing its annual report and may also retain
5		the services of its expert consulting firm used to develop its
6		procurement plans as outlined in paragraph (1) of subsection
7		(a) of Section 1-75. Confidential or commercially sensitive
8		business information provided by retail customers, alternative
9		retail electric suppliers, or other parties shall be kept
10		confidential by the Agency consistent with Section 1-120, but
11		may be publicly reported in aggregate form.
12		(Source: P.A. 102-662, eff. 9-15-21.)
13		Section 90-14. The State Finance Act is amended by
14		changing Sections 5.136, 5.427, and 8.3 as follows:
15		(30 ILCS 105/5.136)
16		Sec. 5.136. The Low-Level Radioactive Waste Facility
17		Development and Operation Fund.
18		(Source: P.A. 99-933, eff. 1-27-17.)
19		(30 ILCS 105/5.427)
20		Sec. 5.427. The Electric Vehicle Rebate and Charging Fund.
21		(Source: P.A. 102-662, eff. 9-15-21.)
22		(30 ILCS 105/8.3)

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1		Sec. 8.3. Money in the Road Fund shall, if and when the
2		State of Illinois incurs any bonded indebtedness for the
3		construction of permanent highways, be set aside and used for
4		the purpose of paying and discharging annually the principal
5		and interest on that bonded indebtedness then due and payable,
6		and for no other purpose. The surplus, if any, in the Road Fund
7		after the payment of principal and interest on that bonded
8		indebtedness then annually due shall be used as follows:
9		first -- to pay the cost of administration of Chapters
10		2 through 10 of the Illinois Vehicle Code, except the cost
11		of administration of Articles I and II of Chapter 3 of that
12		Code, and to pay the costs of the Executive Ethics
13		Commission for oversight and administration of the Chief
14		Procurement Officer appointed under paragraph (2) of
15		subsection (a) of Section 10-20 of the Illinois
16		Procurement Code for transportation; and
17		secondly -- for expenses of the Department of
18		Transportation for construction, reconstruction,
19		improvement, repair, maintenance, operation, and
20		administration of highways in accordance with the
21		provisions of laws relating thereto, or for any purpose
22		related or incident to and connected therewith, including
23		the separation of grades of those highways with railroads
24		and with highways and including the payment of awards made
25		by the Illinois Workers' Compensation Commission under the
26		terms of the Workers' Compensation Act or Workers'

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1		Occupational Diseases Act for injury or death of an
2		employee of the Division of Highways in the Department of
3		Transportation; or for the acquisition of land and the
4		erection of buildings for highway purposes, including the
5		acquisition of highway right-of-way or for investigations
6		to determine the reasonably anticipated future highway
7		needs; or for making of surveys, plans, specifications and
8		estimates for and in the construction and maintenance of
9		flight strips and of highways necessary to provide access
10		to military and naval reservations, to defense industries
11		and defense-industry sites, and to the sources of raw
12		materials and for replacing existing highways and highway
13		connections shut off from general public use at military
14		and naval reservations and defense-industry sites, or for
15		the purchase of right-of-way, except that the State shall
16		be reimbursed in full for any expense incurred in building
17		the flight strips; or for the operating and maintaining of
18		highway garages; or for patrolling and policing the public
19		highways and conserving the peace; or for the operating
20		expenses of the Department relating to the administration
21		of public transportation programs; or, during fiscal year
22		2024, for the purposes of a grant not to exceed $9,108,400
23		to the Regional Transportation Authority on behalf of PACE
24		for the purpose of ADA/Para-transit expenses; or, during
25		fiscal year 2025, for the purposes of a grant not to exceed
26		$10,020,000 to the Regional Transportation Authority on

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

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

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

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

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1		of ADA/Para-transit expenses, and the costs for patrolling
2		and policing the public highways (by the State, political
3		subdivision, or municipality collecting that money) for
4		enforcement of traffic laws. The separation of grades of
5		such highways with railroads and costs associated with
6		protection of at-grade highway and railroad crossing shall
7		also be permissible.
8		Appropriations for any of such purposes are payable from
9		the Road Fund or the Grade Crossing Protection Fund as
10		provided in Section 8 of the Motor Fuel Tax Law.
11		Except as provided in this paragraph, beginning with
12		fiscal year 1991 and thereafter, no Road Fund monies shall be
13		appropriated to the Illinois State Police for the purposes of
14		this Section in excess of its total fiscal year 1990 Road Fund
15		appropriations for those purposes unless otherwise provided in
16		Section 5g of this Act. For fiscal years 2003, 2004, 2005,
17		2006, and 2007 only, no Road Fund monies shall be appropriated
18		to the Department of State Police for the purposes of this
19		Section in excess of $97,310,000. For fiscal year 2008 only,
20		no Road Fund monies shall be appropriated to the Department of
21		State Police for the purposes of this Section in excess of
22		$106,100,000. For fiscal year 2009 only, no Road Fund monies
23		shall be appropriated to the Department of State Police for
24		the purposes of this Section in excess of $114,700,000.
25		Beginning in fiscal year 2010, no Road Fund moneys shall be
26		appropriated to the Illinois State Police. It shall not be

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1		lawful to circumvent this limitation on appropriations by
2		governmental reorganization or other methods unless otherwise
3		provided in Section 5g of this Act.
4		In fiscal year 1994, no Road Fund monies shall be
5		appropriated to the Secretary of State for the purposes of
6		this Section in excess of the total fiscal year 1991 Road Fund
7		appropriations to the Secretary of State for those purposes,
8		plus $9,800,000. It shall not be lawful to circumvent this
9		limitation on appropriations by governmental reorganization or
10		other method.
11		Beginning with fiscal year 1995 and thereafter, no Road
12		Fund monies shall be appropriated to the Secretary of State
13		for the purposes of this Section in excess of the total fiscal
14		year 1994 Road Fund appropriations to the Secretary of State
15		for those purposes. It shall not be lawful to circumvent this
16		limitation on appropriations by governmental reorganization or
17		other methods.
18		Beginning with fiscal year 2000, total Road Fund
19		appropriations to the Secretary of State for the purposes of
20		this Section shall not exceed the amounts specified for the
21		following fiscal years:
22     Fiscal Year 2000 $80,500,000; 23     Fiscal Year 2001 $80,500,000; 24     Fiscal Year 2002 $80,500,000; 25     Fiscal Year 2003 $130,500,000; 26     Fiscal Year 2004 $130,500,000;

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1     Fiscal Year 2005 $130,500,000; 2     Fiscal Year 2006 $130,500,000; 3     Fiscal Year 2007 $130,500,000; 4     Fiscal Year 2008 $130,500,000; 5     Fiscal Year 2009 $130,500,000.
6		For fiscal year 2010, no road fund moneys shall be
7		appropriated to the Secretary of State.
8		Beginning in fiscal year 2011, moneys in the Road Fund
9		shall be appropriated to the Secretary of State for the
10		exclusive purpose of paying refunds due to overpayment of fees
11		related to Chapter 3 of the Illinois Vehicle Code unless
12		otherwise provided for by law.
13		Beginning in fiscal year 2025, moneys in the Road Fund may
14		be appropriated to the Environmental Protection Agency for the
15		exclusive purpose of making deposits into the Electric Vehicle
16		Rebate and Charging Fund, subject to appropriation, to be used
17		for purposes consistent with Section 11 of Article IX of the
18		Illinois Constitution.
19		It shall not be lawful to circumvent this limitation on
20		appropriations by governmental reorganization or other
21		methods.
22		No new program may be initiated in fiscal year 1991 and
23		thereafter that is not consistent with the limitations imposed
24		by this Section for fiscal year 1984 and thereafter, insofar
25		as appropriation of Road Fund monies is concerned.
26		Nothing in this Section prohibits transfers from the Road

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1		Fund to the State Construction Account Fund under Section 5e
2		of this Act; nor to the General Revenue Fund, as authorized by
3		Public Act 93-25.
4		The additional amounts authorized for expenditure in this
5		Section by Public Acts 92-0600, 93-0025, 93-0839, and 94-91
6		shall be repaid to the Road Fund from the General Revenue Fund
7		in the next succeeding fiscal year that the General Revenue
8		Fund has a positive budgetary balance, as determined by
9		generally accepted accounting principles applicable to
10		government.
11		The additional amounts authorized for expenditure by the
12		Secretary of State and the Department of State Police in this
13		Section by Public Act 94-91 shall be repaid to the Road Fund
14		from the General Revenue Fund in the next succeeding fiscal
15		year that the General Revenue Fund has a positive budgetary
16		balance, as determined by generally accepted accounting
17		principles applicable to government.
18		(Source: P.A. 102-16, eff. 6-17-21; 102-538, eff. 8-20-21;
19		102-699, eff. 4-19-22; 102-813, eff. 5-13-22; 103-8, eff.
20		6-7-23; 103-34, eff. 1-1-24; 103-588, eff. 6-5-24; 103-605,
21		eff. 7-1-24; 103-616, eff. 7-1-24; revised 8-5-24.)
22		Section 90-15. The Illinois Procurement Code is amended by
23		changing Sections 1-10 and 30-20 as follows:
24		(30 ILCS 500/1-10)

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1		Sec. 1-10. Application.
2		(a) This Code applies only to procurements for which
3		bidders, offerors, potential contractors, or contractors were
4		first solicited on or after July 1, 1998. This Code shall not
5		be construed to affect or impair any contract, or any
6		provision of a contract, entered into based on a solicitation
7		prior to the implementation date of this Code as described in
8		Article 99, including, but not limited to, any covenant
9		entered into with respect to any revenue bonds or similar
10		instruments. All procurements for which contracts are
11		solicited between the effective date of Articles 50 and 99 and
12		July 1, 1998 shall be substantially in accordance with this
13		Code and its intent.
14		(b) This Code shall apply regardless of the source of the
15		funds with which the contracts are paid, including federal
16		assistance moneys. This Code shall not apply to:
17		(1) Contracts between the State and its political
18		subdivisions or other governments, or between State
19		governmental bodies, except as specifically provided in
20		this Code.
21		(2) Grants, except for the filing requirements of
22		Section 20-80.
23		(3) Purchase of care, except as provided in Section
24		5-30.6 of the Illinois Public Aid Code and this Section.
25		(4) Hiring of an individual as an employee and not as
26		an independent contractor, whether pursuant to an

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1		employment code or policy or by contract directly with
2		that individual.
3		(5) Collective bargaining contracts.
4		(6) Purchase of real estate, except that notice of
5		this type of contract with a value of more than $25,000
6		must be published in the Procurement Bulletin within 10
7		calendar days after the deed is recorded in the county of
8		jurisdiction. The notice shall identify the real estate
9		purchased, the names of all parties to the contract, the
10		value of the contract, and the effective date of the
11		contract.
12		(7) Contracts necessary to prepare for anticipated
13		litigation, enforcement actions, or investigations,
14		provided that the chief legal counsel to the Governor
15		shall give his or her prior approval when the procuring
16		agency is one subject to the jurisdiction of the Governor,
17		and provided that the chief legal counsel of any other
18		procuring entity subject to this Code shall give his or
19		her prior approval when the procuring entity is not one
20		subject to the jurisdiction of the Governor.
21		(8) (Blank).
22		(9) Procurement expenditures by the Illinois
23		Conservation Foundation when only private funds are used.
24		(10) (Blank).
25		(11) Public-private agreements entered into according
26		to the procurement requirements of Section 20 of the

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1		Public-Private Partnerships for Transportation Act and
2		design-build agreements entered into according to the
3		procurement requirements of Section 25 of the
4		Public-Private Partnerships for Transportation Act.
5		(12) (A) Contracts for legal, financial, and other
6		professional and artistic services entered into by the
7		Illinois Finance Authority in which the State of Illinois
8		is not obligated. Such contracts shall be awarded through
9		a competitive process authorized by the members of the
10		Illinois Finance Authority and are subject to Sections
11		5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code,
12		as well as the final approval by the members of the
13		Illinois Finance Authority of the terms of the contract.
14		(B) Contracts for legal and financial services entered
15		into by the Illinois Housing Development Authority in
16		connection with the issuance of bonds in which the State
17		of Illinois is not obligated. Such contracts shall be
18		awarded through a competitive process authorized by the
19		members of the Illinois Housing Development Authority and
20		are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35,
21		and 50-37 of this Code, as well as the final approval by
22		the members of the Illinois Housing Development Authority
23		of the terms of the contract.
24		(13) Contracts for services, commodities, and
25		equipment to support the delivery of timely forensic
26		science services in consultation with and subject to the

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1		approval of the Chief Procurement Officer as provided in
2		subsection (d) of Section 5-4-3a of the Unified Code of
3		Corrections, except for the requirements of Sections
4		20-60, 20-65, 20-70, and 20-160 and Article 50 of this
5		Code; however, the Chief Procurement Officer may, in
6		writing with justification, waive any certification
7		required under Article 50 of this Code. For any contracts
8		for services which are currently provided by members of a
9		collective bargaining agreement, the applicable terms of
10		the collective bargaining agreement concerning
11		subcontracting shall be followed.
12		On and after January 1, 2019, this paragraph (13),
13		except for this sentence, is inoperative.
14		(14) Contracts for participation expenditures required
15		by a domestic or international trade show or exhibition of
16		an exhibitor, member, or sponsor.
17		(15) Contracts with a railroad or utility that
18		requires the State to reimburse the railroad or utilities
19		for the relocation of utilities for construction or other
20		public purpose. Contracts included within this paragraph
21		(15) shall include, but not be limited to, those
22		associated with: relocations, crossings, installations,
23		and maintenance. For the purposes of this paragraph (15),
24		"railroad" means any form of non-highway ground
25		transportation that runs on rails or electromagnetic
26		guideways and "utility" means: (1) public utilities as

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1		defined in Section 3-105 of the Public Utilities Act, (2)
2		telecommunications carriers as defined in Section 13-202
3		of the Public Utilities Act, (3) electric cooperatives as
4		defined in Section 3.4 of the Electric Supplier Act, (4)
5		telephone or telecommunications cooperatives as defined in
6		Section 13-212 of the Public Utilities Act, (5) rural
7		water or waste water systems with 10,000 connections or
8		less, (6) a holder as defined in Section 21-201 of the
9		Public Utilities Act, and (7) municipalities owning or
10		operating utility systems consisting of public utilities
11		as that term is defined in Section 11-117-2 of the
12		Illinois Municipal Code.
13		(16) Procurement expenditures necessary for the
14		Department of Public Health to provide the delivery of
15		timely newborn screening services in accordance with the
16		Newborn Metabolic Screening Act.
17		(17) Procurement expenditures necessary for the
18		Department of Agriculture, the Department of Financial and
19		Professional Regulation, the Department of Human Services,
20		and the Department of Public Health to implement the
21		Compassionate Use of Medical Cannabis Program and Opioid
22		Alternative Pilot Program requirements and ensure access
23		to medical cannabis for patients with debilitating medical
24		conditions in accordance with the Compassionate Use of
25		Medical Cannabis Program Act.
26		(18) This Code does not apply to any procurements

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1		necessary for the Department of Agriculture, the
2		Department of Financial and Professional Regulation, the
3		Department of Human Services, the Department of Commerce
4		and Economic Opportunity, and the Department of Public
5		Health to implement the Cannabis Regulation and Tax Act if
6		the applicable agency has made a good faith determination
7		that it is necessary and appropriate for the expenditure
8		to fall within this exemption and if the process is
9		conducted in a manner substantially in accordance with the
10		requirements of Sections 20-160, 25-60, 30-22, 50-5,
11		50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35,
12		50-36, 50-37, 50-38, and 50-50 of this Code; however, for
13		Section 50-35, compliance applies only to contracts or
14		subcontracts over $100,000. Notice of each contract
15		entered into under this paragraph (18) that is related to
16		the procurement of goods and services identified in
17		paragraph (1) through (9) of this subsection shall be
18		published in the Procurement Bulletin within 14 calendar
19		days after contract execution. The Chief Procurement
20		Officer shall prescribe the form and content of the
21		notice. Each agency shall provide the Chief Procurement
22		Officer, on a monthly basis, in the form and content
23		prescribed by the Chief Procurement Officer, a report of
24		contracts that are related to the procurement of goods and
25		services identified in this subsection. At a minimum, this
26		report shall include the name of the contractor, a

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1		description of the supply or service provided, the total
2		amount of the contract, the term of the contract, and the
3		exception to this Code utilized. A copy of any or all of
4		these contracts shall be made available to the Chief
5		Procurement Officer immediately upon request. The Chief
6		Procurement Officer shall submit a report to the Governor
7		and General Assembly no later than November 1 of each year
8		that includes, at a minimum, an annual summary of the
9		monthly information reported to the Chief Procurement
10		Officer. This exemption becomes inoperative 5 years after
11		June 25, 2019 (the effective date of Public Act 101-27).
12		(19) Acquisition of modifications or adjustments,
13		limited to assistive technology devices and assistive
14		technology services, adaptive equipment, repairs, and
15		replacement parts to provide reasonable accommodations (i)
16		that enable a qualified applicant with a disability to
17		complete the job application process and be considered for
18		the position such qualified applicant desires, (ii) that
19		modify or adjust the work environment to enable a
20		qualified current employee with a disability to perform
21		the essential functions of the position held by that
22		employee, (iii) to enable a qualified current employee
23		with a disability to enjoy equal benefits and privileges
24		of employment as are enjoyed by other similarly situated
25		employees without disabilities, and (iv) that allow a
26		customer, client, claimant, or member of the public

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1		seeking State services full use and enjoyment of and
2		access to its programs, services, or benefits.
3		For purposes of this paragraph (19):
4		"Assistive technology devices" means any item, piece
5		of equipment, or product system, whether acquired
6		commercially off the shelf, modified, or customized, that
7		is used to increase, maintain, or improve functional
8		capabilities of individuals with disabilities.
9		"Assistive technology services" means any service that
10		directly assists an individual with a disability in
11		selection, acquisition, or use of an assistive technology
12		device.
13		"Qualified" has the same meaning and use as provided
14		under the federal Americans with Disabilities Act when
15		describing an individual with a disability.
16		(20) Procurement expenditures necessary for the
17		Illinois Commerce Commission to hire third-party
18		facilitators pursuant to Sections 16-105.17 and 16-108.18
19		of the Public Utilities Act or an ombudsman pursuant to
20		Section 16-107.5 of the Public Utilities Act, a
21		facilitator pursuant to Section 16-105.17 of the Public
22		Utilities Act, or a grid auditor pursuant to Section
23		16-105.10 of the Public Utilities Act, a facilitator,
24		expert, or consultant pursuant to Sections 16-126.2 and
25		16-202 of the Public Utilities Act, a procurement monitor
26		pursuant to Section 16-111.5 of the Public Utilities Act,

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1		an ombudsperson pursuant to Section 20-145 of the Public
2		Utilities Act, or consultants and experts pursuant to
3		Section 5-15 of the Utility Data Access Act.
4		(21) Procurement expenditures for the purchase,
5		renewal, and expansion of software, software licenses, or
6		software maintenance agreements that support the efforts
7		of the Illinois State Police to enforce, regulate, and
8		administer the Firearm Owners Identification Card Act, the
9		Firearm Concealed Carry Act, the Firearms Restraining
10		Order Act, the Firearm Dealer License Certification Act,
11		the Law Enforcement Agencies Data System (LEADS), the
12		Uniform Crime Reporting Act, the Criminal Identification
13		Act, the Illinois Uniform Conviction Information Act, and
14		the Gun Trafficking Information Act, or establish or
15		maintain record management systems necessary to conduct
16		human trafficking investigations or gun trafficking or
17		other stolen firearm investigations. This paragraph (21)
18		applies to contracts entered into on or after January 10,
19		2023 (the effective date of Public Act 102-1116) and the
20		renewal of contracts that are in effect on January 10,
21		2023 (the effective date of Public Act 102-1116).
22		(22) Contracts for project management services and
23		system integration services required for the completion of
24		the State's enterprise resource planning project. This
25		exemption becomes inoperative 5 years after June 7, 2023
26		(the effective date of the changes made to this Section by

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1		Public Act 103-8). This paragraph (22) applies to
2		contracts entered into on or after June 7, 2023 (the
3		effective date of the changes made to this Section by
4		Public Act 103-8) and the renewal of contracts that are in
5		effect on June 7, 2023 (the effective date of the changes
6		made to this Section by Public Act 103-8).
7		(23) Procurements necessary for the Department of
8		Insurance to implement the Illinois Health Benefits
9		Exchange Law if the Department of Insurance has made a
10		good faith determination that it is necessary and
11		appropriate for the expenditure to fall within this
12		exemption. The procurement process shall be conducted in a
13		manner substantially in accordance with the requirements
14		of Sections 20-160 and 25-60 and Article 50 of this Code. A
15		copy of these contracts shall be made available to the
16		Chief Procurement Officer immediately upon request. This
17		paragraph is inoperative 5 years after June 27, 2023 (the
18		effective date of Public Act 103-103).
19		(24) Contracts for public education programming,
20		noncommercial sustaining announcements, public service
21		announcements, and public awareness and education
22		messaging with the nonprofit trade associations of the
23		providers of those services that inform the public on
24		immediate and ongoing health and safety risks and hazards.
25		(25) Procurements necessary for the Department of
26		Early Childhood to implement the Department of Early

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1		Childhood Act if the Department has made a good faith
2		determination that it is necessary and appropriate for the
3		expenditure to fall within this exemption. This exemption
4		shall only be used for products and services procured
5		solely for use by the Department of Early Childhood. The
6		procurements may include those necessary to design and
7		build integrated, operational systems of programs and
8		services. The procurements may include, but are not
9		limited to, those necessary to align and update program
10		standards, integrate funding systems, design and establish
11		data and reporting systems, align and update models for
12		technical assistance and professional development, design
13		systems to manage grants and ensure compliance, design and
14		implement management and operational structures, and
15		establish new means of engaging with families, educators,
16		providers, and stakeholders. The procurement processes
17		shall be conducted in a manner substantially in accordance
18		with the requirements of Article 50 (ethics) and Sections
19		5-5 (Procurement Policy Board), 5-7 (Commission on Equity
20		and Inclusion), 20-80 (contract files), 20-120
21		(subcontractors), 20-155 (paperwork), 20-160
22		(ethics/campaign contribution prohibitions), 25-60
23		(prevailing wage), and 25-90 (prohibited and authorized
24		cybersecurity) of this Code. Beginning January 1, 2025,
25		the Department of Early Childhood shall provide a
26		quarterly report to the General Assembly detailing a list

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1		of expenditures and contracts for which the Department
2		uses this exemption. This paragraph is inoperative on and
3		after July 1, 2027.
4		(26) (25) Procurements that are necessary for
5		increasing the recruitment and retention of State
6		employees, particularly minority candidates for
7		employment, including:
8		(A) procurements related to registration fees for
9		job fairs and other outreach and recruitment events;
10		(B) production of recruitment materials; and
11		(C) other services related to recruitment and
12		retention of State employees.
13		The exemption under this paragraph (26) (25) applies
14		only if the State agency has made a good faith
15		determination that it is necessary and appropriate for the
16		expenditure to fall within this paragraph (26) (25). The
17		procurement process under this paragraph (26) (25) shall
18		be conducted in a manner substantially in accordance with
19		the requirements of Sections 20-160 and 25-60 and Article
20		50 of this Code. A copy of these contracts shall be made
21		available to the Chief Procurement Officer immediately
22		upon request. Nothing in this paragraph (26) (25)
23		authorizes the replacement or diminishment of State
24		responsibilities in hiring or the positions that
25		effectuate that hiring. This paragraph (26) (25) is
26		inoperative on and after June 30, 2029.

SB0025 Enrolled - 443 - LRB104 07069 BAB 17106 b
1		Notwithstanding any other provision of law, for contracts
2		with an annual value of more than $100,000 entered into on or
3		after October 1, 2017 under an exemption provided in any
4		paragraph of this subsection (b), except paragraph (1), (2),
5		or (5), each State agency shall post to the appropriate
6		procurement bulletin the name of the contractor, a description
7		of the supply or service provided, the total amount of the
8		contract, the term of the contract, and the exception to the
9		Code utilized. The chief procurement officer shall submit a
10		report to the Governor and General Assembly no later than
11		November 1 of each year that shall include, at a minimum, an
12		annual summary of the monthly information reported to the
13		chief procurement officer.
14		(c) This Code does not apply to the electric power
15		procurement process provided for under Section 1-75 of the
16		Illinois Power Agency Act and Section 16-111.5 of the Public
17		Utilities Act. This Code does not apply to the procurement of
18		technical and policy experts pursuant to Section 1-129 of the
19		Illinois Power Agency Act.
20		(d) Except for Section 20-160 and Article 50 of this Code,
21		and as expressly required by Section 9.1 of the Illinois
22		Lottery Law, the provisions of this Code do not apply to the
23		procurement process provided for under Section 9.1 of the
24		Illinois Lottery Law.
25		(e) This Code does not apply to the process used by the
26		Capital Development Board to retain a person or entity to

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1		assist the Capital Development Board with its duties related
2		to the determination of costs of a clean coal SNG brownfield
3		facility, as defined by Section 1-10 of the Illinois Power
4		Agency Act, as required in subsection (h-3) of Section 9-220
5		of the Public Utilities Act, including calculating the range
6		of capital costs, the range of operating and maintenance
7		costs, or the sequestration costs or monitoring the
8		construction of clean coal SNG brownfield facility for the
9		full duration of construction.
10		(f) (Blank).
11		(g) (Blank).
12		(h) This Code does not apply to the process to procure or
13		contracts entered into in accordance with Sections 11-5.2 and
14		11-5.3 of the Illinois Public Aid Code.
15		(i) Each chief procurement officer may access records
16		necessary to review whether a contract, purchase, or other
17		expenditure is or is not subject to the provisions of this
18		Code, unless such records would be subject to attorney-client
19		privilege.
20		(j) This Code does not apply to the process used by the
21		Capital Development Board to retain an artist or work or works
22		of art as required in Section 14 of the Capital Development
23		Board Act.
24		(k) This Code does not apply to the process to procure
25		contracts, or contracts entered into, by the State Board of
26		Elections or the State Electoral Board for hearing officers

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1		appointed pursuant to the Election Code.
2		(l) This Code does not apply to the processes used by the
3		Illinois Student Assistance Commission to procure supplies and
4		services paid for from the private funds of the Illinois
5		Prepaid Tuition Fund. As used in this subsection (l), "private
6		funds" means funds derived from deposits paid into the
7		Illinois Prepaid Tuition Trust Fund and the earnings thereon.
8		(m) This Code shall apply regardless of the source of
9		funds with which contracts are paid, including federal
10		assistance moneys. Except as specifically provided in this
11		Code, this Code shall not apply to procurement expenditures
12		necessary for the Department of Public Health to conduct the
13		Healthy Illinois Survey in accordance with Section 2310-431 of
14		the Department of Public Health Powers and Duties Law of the
15		Civil Administrative Code of Illinois.
16		(Source: P.A. 102-175, eff. 7-29-21; 102-483, eff 1-1-22;
17		102-558, eff. 8-20-21; 102-600, eff. 8-27-21; 102-662, eff.
18		9-15-21; 102-721, eff. 1-1-23; 102-813, eff. 5-13-22;
19		102-1116, eff. 1-10-23; 103-8, eff. 6-7-23; 103-103, eff.
20		6-27-23; 103-570, eff. 1-1-24; 103-580, eff. 12-8-23; 103-594,
21		eff. 6-25-24; 103-605, eff. 7-1-24; 103-865, eff. 1-1-25;
22		revised 11-26-24.)
23		(30 ILCS 500/30-20)
24		Sec. 30-20. Prequalification.
25		(a) The Capital Development Board shall promulgate rules

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

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1		preapprenticeship skills training, for which participants may
2		attend free of charge and receive a stipend, to create a
3		qualified, diverse pipeline of workers who are prepared for
4		careers in the construction and building trades. Upon
5		completion of the Illinois Works Preapprenticeship Program,
6		the candidates will be skilled and work-ready.
7		(b) There is created the Illinois Works Fund, a special
8		fund in the State treasury. The Illinois Works Fund shall be
9		administered by the Department. The Illinois Works Fund shall
10		be used to provide funding for community-based organizations
11		throughout the State. In addition to any other transfers that
12		may be provided for by law, on and after July 1, 2019 at the
13		direction of the Director of the Governor's Office of
14		Management and Budget, the State Comptroller shall direct and
15		the State Treasurer shall transfer amounts not exceeding a
16		total of $50,000,000 from the Rebuild Illinois Projects Fund
17		to the Illinois Works Fund.
18		(b-5) In addition to any other transfers that may be
19		provided for by law, beginning July 1, 2024 and each July 1
20		thereafter, or as soon thereafter as practical, the State
21		Comptroller shall direct and the State Treasurer shall
22		transfer $27,500,000 from the Capital Projects Fund to the
23		Illinois Works Fund.
24		(c) Each community-based organization that receives
25		funding from the Illinois Works Fund shall provide an annual
26		report to the Illinois Works Review Panel by April 1 of each

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1		calendar year. The annual report shall include the following
2		information:
3		(1) a description of the community-based
4		organization's recruitment, screening, and training
5		efforts;
6		(2) the number of individuals who apply to,
7		participate in, and complete the community-based
8		organization's program, broken down by race, gender, age,
9		and veteran status; and
10		(3) the number of the individuals referenced in item (2)
11		of this subsection who are initially accepted and placed
12		into apprenticeship programs in the construction and
13		building trades.
14		(d) The Department shall create and administer the
15		Illinois Works Bid Credit Program that shall provide economic
16		incentives, through bid credits, to encourage contractors and
17		subcontractors to provide contracting and employment
18		opportunities to historically underrepresented populations in
19		the construction industry.
20		The Illinois Works Bid Credit Program shall allow
21		contractors and subcontractors to earn bid credits for use
22		toward future bids for public works projects contracted by the
23		State or an agency of the State in order to increase the
24		chances that the contractor and the subcontractors will be
25		selected.
26		Contractors or subcontractors may be eligible to earn bid

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1		credits for employing apprentices who have been verified by
2		the Department to have completed the Illinois Works
3		Preapprenticeship Program, the Climate Works Preapprenticeship
4		Program, or the Highway Construction Careers Training Program.
5		Contractors or subcontractors shall earn bid credits at a rate
6		established by the Department and based on labor hours worked
7		by apprentices who have been verified by the Department to
8		have completed the Illinois Works Preapprenticeship Program,
9		the Climate Works Preapprenticeship Program, or the Highway
10		Construction Careers Training Program. In order to earn bid
11		credits, contractors and subcontractors shall provide the
12		Department with certified payroll documenting the hours
13		performed by apprentices who have been verified by the
14		Department to have completed the Illinois Works
15		Preapprenticeship Program, the Climate Works Preapprenticeship
16		Program, or the Highway Construction Careers Training Program.
17		Contractors and subcontractors can use bid credits toward
18		future bids for public works projects contracted or funded by
19		the State or an agency of the State in order to increase the
20		likelihood of being selected as the contractor for the public
21		works project toward which they have applied the bid credit.
22		The Department shall establish the rate by rule and shall
23		publish it on the Department's website. The rule may include
24		maximum bid credits allowed per contractor, per subcontractor,
25		per apprentice, per bid, or per year.
26		The Illinois Works Credit Bank is hereby created and shall

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1		be administered by the Department. The Illinois Works Credit
2		Bank shall track the bid credits.
3		A contractor or subcontractor who has been awarded bid
4		credits under any other State program for employing
5		apprentices who have completed the Illinois Works
6		Preapprenticeship Program is not eligible to receive bid
7		credits under the Illinois Works Bid Credit Program relating
8		to the same contract.
9		The Department shall report to the Illinois Works Review
10		Panel the following: (i) the number of bid credits awarded by
11		the Department; (ii) the number of bid credits submitted by
12		the contractor or subcontractor to the agency administering
13		the public works contract; and (iii) the number of bid credits
14		accepted by the agency for such contract. Any agency that
15		awards bid credits pursuant to the Illinois Works Credit Bank
16		Program shall report to the Department the number of bid
17		credits it accepted for the public works contract.
18		Upon a finding that a contractor or subcontractor has
19		reported falsified records to the Department in order to
20		fraudulently obtain bid credits, the Department may bar the
21		contractor or subcontractor from participating in the Illinois
22		Works Bid Credit Program and may suspend the contractor or
23		subcontractor from bidding on or participating in any public
24		works project. False or fraudulent claims for payment relating
25		to false bid credits may be subject to damages and penalties
26		under applicable law.

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1		(e) The Department shall adopt any rules deemed necessary
2		to implement this Section. In order to provide for the
3		expeditious and timely implementation of this Act, the
4		Department may adopt emergency rules. The adoption of
5		emergency rules authorized by this subsection is deemed to be
6		necessary for the public interest, safety, and welfare.
7		(Source: P.A. 103-8, eff. 6-7-23; 103-305, eff. 7-28-23;
8		103-588, eff. 6-5-24; 103-605, eff. 7-1-24; 104-2, eff.
9		6-16-25.)
10		Section 90-20. The Property Tax Code is amended by adding
11		Division 22 as follows:
12		(35 ILCS 200/Art. 10 Div. 22 heading new)
13		Division 22. Commercial energy storage systems
14		(35 ILCS 200/10-920 new)
15		Sec. 10-920. Definitions. As used in this Division:
16		"Allowance for physical depreciation" means the product of
17		the quotient that is generated by dividing the actual age in
18		years of the commercial energy storage system on the
19		assessment date by 25 years multiplied by the commercial
20		energy storage system's trended real property cost basis.
21		"Allowance for physical depreciation" may not exceed an amount
22		that reduces the value of the commercial energy storage system
23		to 30% of its trended real property cost basis or less.

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

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1		Statistics in the December immediately preceding the
2		assessment date by the Consumer Price Index published by
3		the Bureau of Labor Statistics in December of 2024; or
4		(2) for commercial energy storage systems tied to a
5		power generation system, a trending factor of 1.00.
6		(35 ILCS 200/10-925 new)
7		Sec. 10-925. Improvement valuation of commercial energy
8		systems. Beginning in assessment year 2026, the fair cash
9		value of commercial energy storage system improvements shall
10		be determined by subtracting the allowance for physical
11		depreciation from the commercial energy storage system trended
12		real property cost basis. Functional obsolescence and external
13		obsolescence of the commercial energy storage system
14		improvements may further reduce the fair cash value of the
15		improvements to the extent the obsolescence is proven by the
16		taxpayer by clear and convincing evidence, except that the
17		combined depreciation from all functional and economic
18		obsolescence shall not exceed 70% of the trended real property
19		cost basis. The chief county assessment officer may make
20		reasonable adjustments to the actual age of the commercial
21		energy storage system to account for the routine replacement
22		or upgrade of system components.
23		(35 ILCS 200/10-930 new)
24		Sec. 10-930. Commercial energy storage systems;

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

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1		improvements, including the land containing the commercial
2		energy storage system, to be used only for the purposes of
3		property assessment for taxation. If no survey is provided,
4		the chief county assessment officer shall determine the area
5		of the site that is occupied by the commercial energy storage
6		system. The chief county assessment officer's determination
7		shall be final and may not be challenged on review by the owner
8		of the commercial energy storage system. The property records
9		shall contain the legal description of the commercial energy
10		storage system parcel and describe any leasehold interest or
11		other interest of the owner of the commercial energy storage
12		system in the property. A plat prepared under this Section
13		shall not be construed as a violation of the Plat Act.
14		Surveys that are prepared in accordance with either
15		Section 10-740 or Section 10-620 and that also include the
16		location of a commercial energy storage system in the survey's
17		metes and bounds description shall satisfy the requirements of
18		this Section.
19		(35 ILCS 200/10-940 new)
20		Sec. 10-940. Real estate taxes. Notwithstanding the
21		provisions of Section 9-175 of this Code, the owner of the
22		commercial energy storage system shall be liable for the real
23		estate taxes for the land and real property improvements of
24		the commercial energy storage system. Notwithstanding the
25		foregoing, the owner of the land upon which a commercial

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1		energy storage system is located may pay any unpaid tax of the
2		commercial energy storage system parcel prior to the
3		initiation of any tax sale proceedings.
4		(35 ILCS 200/10-945 new)
5		Sec. 10-945. Property assessed as farmland.
6		Notwithstanding any other provision of law, real property
7		assessed as farmland in accordance with Section 10-110 in the
8		assessment year prior to valuation under this Division shall
9		return to being assessed as farmland in accordance with
10		Section 10-110 in the year following completion of the removal
11		of the commercial energy storage system if the property is
12		returned to a farm use, as defined in Section 1-60,
13		notwithstanding that the land was not used for farming for the
14		2 preceding years.
15		(35 ILCS 200/10-950 new)
16		Sec. 10-950. Abatements. Any taxing district may, upon a
17		majority vote of its governing authority and after the
18		determination of the assessed valuation as set forth in this
19		Code, order the clerk of the appropriate municipality or
20		county to abate any portion of real property taxes otherwise
21		levied or extended by the taxing district on a commercial
22		energy storage system.
23		(35 ILCS 200/10-953 new)

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1		Sec. 10-953. Cook County exemption. This Division 22 does
2		not apply to any property located within Cook County.
3		(35 ILCS 200/10-955 new)
4		Sec. 10-955. Applicability. The provisions of this
5		Division apply for assessment years 2026 through 2040.
6		Section 90-22. The Radioactive Waste Compact Enforcement
7		Act is amended by changing Section 15, 25, 30, and 31 as
8		follows:
9		(45 ILCS 141/15)
10		Sec. 15. Definitions. In this Act:
11		"IEMA-OHS" means the Illinois Emergency Management Agency
12		and Office of Homeland Security, or its successor agency.
13		"Commission" means the Central Midwest Interstate
14		Low-Level Radioactive Waste Commission.
15		"Compact" means the Central Midwest Interstate Low-Level
16		Radioactive Waste Compact.
17		"Director" means the Director of IEMA-OHS.
18		"Disposal" means the isolation of waste from the biosphere
19		in a permanent facility designed for that purpose.
20		"Facility" means a parcel of land or site, together with
21		the structures, equipment, and improvements on or appurtenant
22		to the land or site, that is used or is being developed for the
23		treatment, storage or disposal of low-level radioactive waste.

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1		"Low-level radioactive waste" or "waste" means radioactive
2		waste not classified as (1) high-level radioactive waste, (2)
3		transuranic waste, (3) spent nuclear fuel, or (4) byproduct
4		material as defined in Sections 11e(2), 11e(3), and 11e(4) of
5		the Atomic Energy Act (42 U.S.C. 2014). This definition shall
6		apply notwithstanding any declaration by the federal
7		government, a state, or any regulatory agency that any
8		radioactive material is exempt from any regulatory control.
9		"Management plan" means the plan adopted by the Commission
10		for the storage, transportation, treatment and disposal of
11		waste within the region.
12		"Nuclear facilities" means nuclear power plants,
13		facilities housing nuclear test and research reactors,
14		facilities for the chemical conversion of uranium, and
15		facilities for the storage of spent nuclear fuel or high-level
16		radioactive waste.
17		"Nuclear power plant" or "nuclear steam-generating
18		facility" means a thermal power plant in which the energy
19		(heat) released by the fissioning of nuclear fuel is used to
20		boil water to produce steam.
21		"Nuclear power reactor" means an apparatus, other than an
22		atomic weapon, designed or used to sustain nuclear fission in
23		a self-supporting chain reaction.
24		"Person" means any individual, corporation, business
25		enterprise or other legal entity, public or private, and any
26		legal successor, representative, agent or agency of that

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1		individual, corporation, business enterprise, or legal entity.
2		"Region" means the geographical area of the State of
3		Illinois and the Commonwealth of Kentucky.
4		"Regional Facility" means any facility as defined in this
5		Act that is (1) located in Illinois, and (2) established by
6		Illinois pursuant to designation of Illinois as a host state
7		by the Commission.
8		"Small modular reactor" or "SMR" means an advanced nuclear
9		reactor: (1) with a rated nameplate capacity of 300 electrical
10		megawatts or less; and (2) that may be constructed and
11		operated in combination with similar reactors at a single
12		site.
13		"Storage" means the temporary holding of radioactive
14		material for treatment or disposal.
15		"Treatment" means any method, technique or process,
16		including storage for radioactive decay, designed to change
17		the physical, chemical, or biological characteristics of the
18		radioactive material in order to render the radioactive
19		material safe for transport or management, amenable to
20		recovery, convertible to another usable material, or reduced
21		in volume.
22		(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24.)
23		(45 ILCS 141/25)
24		Sec. 25. Enforcement.
25		(a) The Agency shall adopt regulations to administer and

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1		enforce the provisions of this Act. The regulations shall be
2		adopted with the consultation and cooperation of the
3		Commission.
4		Regulations adopted by the Agency under this Act shall
5		prohibit the shipment into or acceptance of waste in Illinois
6		if the shipment or acceptance would result in a violation of
7		any provision of the Compact or this Act.
8		(b) The Agency may, by regulation, impose conditions on
9		the shipment into or acceptance of waste in Illinois that the
10		Agency determines to be reasonable and necessary to enforce
11		the provisions of this Act. The conditions may include, but
12		are not limited to (i) requiring prior notification of any
13		proposed shipment or receipt of waste; (ii) requiring the
14		shipper or recipient to identify the location to which the
15		waste will be sent for disposal following treatment or storage
16		in Illinois; (iii) limiting the time that waste from outside
17		Illinois may be held in Illinois; (iv) requiring the shipper
18		or recipient to post bond or by other mechanism to assure that
19		radioactive material will not be treated, stored, or disposed
20		of in Illinois in violation of any provision of this Act; (v)
21		requiring that the shipper consent to service of process
22		before shipment of waste into Illinois.
23		(c) The Agency shall, by regulation, impose a system of
24		civil penalties in accordance with the provisions of this Act.
25		Amounts recovered under these regulations shall be deposited
26		in the Low-Level Radioactive Waste Facility Development and

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1		Operation Fund.
2		(d) The regulations adopted by the Agency may provide for
3		the granting of exemptions, but only upon a showing by the
4		applicant that the granting of an exemption would be
5		consistent with the Compact.
6		(Source: P.A. 103-569, eff. 6-1-24.)
7		(45 ILCS 141/30)
8		Sec. 30. Penalties.
9		(a) Any person who ships or receives radioactive material
10		in violation of any provision of this Act or a regulation of
11		the Agency adopted under this Act shall be subject to a civil
12		penalty not to exceed $100,000 per occurrence.
13		(b) Any person who fails to pay a civil penalty imposed by
14		regulations adopted under this Act, or any portion of the
15		penalty, shall be liable in a civil action in an amount not to
16		exceed 4 times the amount imposed and not paid.
17		(c) Any person who intentionally violates a provision of
18		subsection (a)(1), (a)(2), (a)(3), (a)(4) or (a)(6) of Section
19		20 of this Act shall be guilty of a Class 4 felony.
20		(d) At the request of the Agency, the Attorney General
21		shall, on behalf of the State, bring an action for the recovery
22		of any civil penalty or the prosecution of any criminal
23		offense provided for by this Act. Any civil penalties so
24		recovered shall be deposited in the Low-Level Radioactive
25		Waste Facility Development and Operation Fund.

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1		(Source: P.A. 95-777, eff. 8-4-08.)
2		(45 ILCS 141/31)
3		Sec. 31. The Agency may accept donations of money,
4		equipment, supplies, materials, and services from any person
5		for accomplishing the purposes of this Act. Any donation of
6		money shall be deposited in the Low-Level Radioactive Waste
7		Facility Development and Operation Fund and shall be expended
8		by the Agency only in accordance with the purposes of the
9		donation.
10		(Source: P.A. 95-777, eff. 8-4-08.)
11		Section 90-27. The Counties Code is amended by adding
12		Division 5-46 and Section 5-12024 and changing Section 5-12020
13		as follows:
14		(55 ILCS 5/5-12020)
15		Sec. 5-12020. Commercial wind energy facilities and
16		commercial solar energy facilities.
17		(a) As used in this Section:
18		"Commercial solar energy facility" means a "commercial
19		solar energy system" as defined in Section 10-720 of the
20		Property Tax Code. "Commercial solar energy facility" does not
21		mean a utility-scale solar energy facility being constructed
22		at a site that was eligible to participate in a procurement
23		event conducted by the Illinois Power Agency pursuant to

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1		subsection (c-5) of Section 1-75 of the Illinois Power Agency
2		Act.
3		"Commercial wind energy facility" means a wind energy
4		conversion facility of equal or greater than 500 kilowatts in
5		total nameplate generating capacity. "Commercial wind energy
6		facility" includes a wind energy conversion facility seeking
7		an extension of a permit to construct granted by a county or
8		municipality before January 27, 2023 (the effective date of
9		Public Act 102-1123).
10		"Facility owner" means (i) a person with a direct
11		ownership interest in a commercial wind energy facility or a
12		commercial solar energy facility, or both, regardless of
13		whether the person is involved in acquiring the necessary
14		rights, permits, and approvals or otherwise planning for the
15		construction and operation of the facility, and (ii) at the
16		time the facility is being developed, a person who is acting as
17		a developer of the facility by acquiring the necessary rights,
18		permits, and approvals or by planning for the construction and
19		operation of the facility, regardless of whether the person
20		will own or operate the facility.
21		"Nonparticipating property" means real property that is
22		not a participating property.
23		"Nonparticipating residence" means a residence that is
24		located on nonparticipating property and that is existing and
25		occupied on the date that an application for a permit to
26		develop the commercial wind energy facility or the commercial

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1		solar energy facility is filed with the county.
2		"Occupied community building" means any one or more of the
3		following buildings that is existing and occupied on the date
4		that the application for a permit to develop the commercial
5		wind energy facility or the commercial solar energy facility
6		is filed with the county: a school, place of worship, day care
7		facility, public library, or community center.
8		"Participating property" means real property that is the
9		subject of a written agreement between a facility owner and
10		the owner of the real property that provides the facility
11		owner an easement, option, lease, or license to use the real
12		property for the purpose of constructing a commercial wind
13		energy facility, a commercial solar energy facility, or
14		supporting facilities. "Participating property" also includes
15		real property that is owned by a facility owner for the purpose
16		of constructing a commercial wind energy facility, a
17		commercial solar energy facility, or supporting facilities.
18		"Participating residence" means a residence that is
19		located on participating property and that is existing and
20		occupied on the date that an application for a permit to
21		develop the commercial wind energy facility or the commercial
22		solar energy facility is filed with the county.
23		"Protected lands" means real property that is:
24		(1) subject to a permanent conservation right
25		consistent with the Real Property Conservation Rights Act;
26		or

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1		(2) registered or designated as a nature preserve,
2		buffer, or land and water reserve under the Illinois
3		Natural Areas Preservation Act.
4		"Supporting facilities" means the transmission lines,
5		substations, access roads, meteorological towers, storage
6		containers, and equipment associated with the generation and
7		storage of electricity by the commercial wind energy facility
8		or commercial solar energy facility. "Supporting facilities"
9		includes energy storage systems capable of absorbing energy
10		and storing it for use at a later time, including, but not
11		limited to, batteries and other electrochemical and
12		electromechanical technologies or systems.
13		"Wind tower" includes the wind turbine tower, nacelle, and
14		blades.
15		(b) Notwithstanding any other provision of law or whether
16		the county has formed a zoning commission and adopted formal
17		zoning under Section 5-12007, a county may establish standards
18		for commercial wind energy facilities, commercial solar energy
19		facilities, or both. The standards may include all of the
20		requirements specified in this Section but may not include
21		requirements for commercial wind energy facilities or
22		commercial solar energy facilities that are more restrictive
23		than specified in this Section. A county may also regulate the
24		siting of commercial wind energy facilities with standards
25		that are not more restrictive than the requirements specified
26		in this Section in unincorporated areas of the county that are

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1		outside the zoning jurisdiction of a municipality and that are
2		outside the 1.5-mile radius surrounding the zoning
3		jurisdiction of a municipality. A county may also regulate the
4		siting of commercial solar energy facilities with standards
5		that are not more restrictive than the requirements specified
6		in this Section in unincorporated areas of the county that are
7		outside of the zoning jurisdiction of a municipality.
8		(c) If a county has elected to establish standards under
9		subsection (b), before the county grants siting approval or a
10		special use permit for a commercial wind energy facility or a
11		commercial solar energy facility, or modification of an
12		approved siting or special use permit, the county board of the
13		county in which the facility is to be sited or the zoning board
14		of appeals for the county shall hold at least one public
15		hearing. The public hearing shall be conducted in accordance
16		with the Open Meetings Act and shall conclude be held not more
17		than 60 days after the filing of the application for the
18		facility. The county shall allow interested parties to a
19		special use permit an opportunity to present evidence and to
20		cross-examine witnesses at the hearing, but the county may
21		impose reasonable restrictions on the public hearing,
22		including reasonable time limitations on the presentation of
23		evidence and the cross-examination of witnesses. The county
24		shall also allow public comment at the public hearing in
25		accordance with the Open Meetings Act. The county shall make
26		its siting and permitting decisions not more than 30 days

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1		after the conclusion of the public hearing. Notice of the
2		hearing shall be published in a newspaper of general
3		circulation in the county. A facility owner must enter into an
4		agricultural impact mitigation agreement with the Department
5		of Agriculture prior to the date of the required public
6		hearing. A commercial wind energy facility owner seeking an
7		extension of a permit granted by a county prior to July 24,
8		2015 (the effective date of Public Act 99-132) must enter into
9		an agricultural impact mitigation agreement with the
10		Department of Agriculture prior to a decision by the county to
11		grant the permit extension. Counties may allow test wind
12		towers or test solar energy systems to be sited without formal
13		approval by the county board.
14		(d) A county with an existing zoning ordinance in conflict
15		with this Section shall amend that zoning ordinance to be in
16		compliance with this Section within 120 days after January 27,
17		2023 (the effective date of Public Act 102-1123).
18		(e) A county may require:
19		(1) a wind tower of a commercial wind energy facility
20		to be sited as follows, with setback distances measured
21		from the center of the base of the wind tower:
22		Setback Description           Setback Distance
23		Occupied Community            2.1 times the maximum blade tip
24		Buildings                     height of the wind tower to the

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1		nearest point on the outside
2		wall of the structure
3		Participating Residences      1.1 times the maximum blade tip
4		height of the wind tower to the
5		nearest point on the outside
6		wall of the structure
7		Nonparticipating Residences   2.1 times the maximum blade tip
8		height of the wind tower to the
9		nearest point on the outside
10		wall of the structure
11		Boundary Lines of             None
12		Participating Property
13		Boundary Lines of             1.1 times the maximum blade tip
14		Nonparticipating Property     height of the wind tower to the
15		nearest point on the property
16		line of the nonparticipating
17		property
18		Public Road Rights-of-Way     1.1 times the maximum blade tip
19		height of the wind tower
20		to the center point of the
21		public road right-of-way

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1		Overhead Communication and    1.1 times the maximum blade tip
2		Electric Transmission         height of the wind tower to the
3		and Distribution Facilities   nearest edge of the property
4		(Not Including Overhead       line, easement, or
5		Utility Service Lines to      right-of-way
6		Individual Houses or          containing the overhead line
7		Outbuildings)
8		Overhead Utility Service      None
9		Lines to Individual
10		Houses or Outbuildings
11		Fish and Wildlife Areas       2.1 times the maximum blade
12		and Illinois Nature           tip height of the wind tower
13		Preserve Commission           to the nearest point on the
14		Protected Lands               property line of the fish and
15		wildlife area or protected
16		land
17		This Section does not exempt or excuse compliance with
18		electric facility clearances approved or required by the
19		National Electrical Code, the The National Electrical
20		Safety Code, the Illinois Commerce Commission, and the
21		Federal Energy Regulatory Commission, and their designees
22		or successors; .
23		(2) a wind tower of a commercial wind energy facility

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1		to be sited so that industry standard computer modeling
2		indicates that any occupied community building or
3		nonparticipating residence will not experience more than
4		30 hours per year of shadow flicker under planned
5		operating conditions;
6		(3) a commercial solar energy facility to be sited as
7		follows, with setback distances measured from the nearest
8		edge of any above-ground component of the facility,
9		excluding fencing:
10		Setback Description           Setback Distance
11		Occupied Community            150 feet from the nearest
12		Buildings and Dwellings on    point on the outside wall
13		Nonparticipating Properties   of the structure
14		Boundary Lines of             None
15		Participating Property
16		Public Road Rights-of-Way     50 feet from the nearest
17		edge of the public
18		right-of-way
19		Boundary Lines of             50 feet to the nearest
20		Nonparticipating Property     point on the property
21		line of the nonparticipating

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1		property
2		(4) a commercial solar energy facility to be sited so
3		that the facility's perimeter is enclosed by fencing
4		having a height of at least 6 feet and no more than 25
5		feet; and
6		(5) a commercial solar energy facility to be sited so
7		that no component of a solar panel has a height of more
8		than 20 feet above ground when the solar energy facility's
9		arrays are at full tilt.
10		This subsection (e) shall not preclude the ability of a
11		county to require a reasonable setback distance between
12		fencing and public rights-of-way if the requirement is not
13		specific to commercial wind energy facilities or commercial
14		solar energy facilities and does not preclude the development
15		of commercial wind energy facilities or commercial solar
16		energy facilities or the ability of commercial wind energy
17		facilities or commercial solar energy facilities to comply
18		with the requirements set forth in this subsection (e).
19		The requirements set forth in this subsection (e) may be
20		waived subject to the written consent of the owner of each
21		affected nonparticipating property.
22		(f) A county may not set a sound limitation for wind towers
23		in commercial wind energy facilities or any components in
24		commercial solar energy facilities that is more restrictive
25		than the sound limitations established by the Illinois

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1		Pollution Control Board under 35 Ill. Adm. Code Parts 900,
2		901, and 910. Additionally, in accordance with Section 25 of
3		the Environmental Protection Act, a participating property,
4		participating residence, nonparticipating property,
5		nonparticipating residence, or any combination of those
6		properties or residences may waive enforcement of the rules
7		adopted by the Illinois Pollution Control Board under 35 Ill.
8		Adm. Code Parts 900, 901, and 910 by written waiver that
9		complies with the applicable directive established in Section
10		25 of the Environmental Protection Act and is recorded in the
11		Office of the Recorder of the county in which the
12		participating property, participating residence,
13		nonparticipating property, or nonparticipating residence is
14		located. Once recorded, such a waiver shall be binding on any
15		current and future owners, residents, lessees, invitees, and
16		users of the participating property, participating residence,
17		nonparticipating property, or nonparticipating residence for
18		enforcement purposes. An owner of any participating residence
19		or nonparticipating residence shall disclose the existence of
20		such a waiver to any lessee before entering any new lease for
21		the residence.
22		A seller or transferor of a participating property,
23		participating residence, nonparticipating property,
24		nonparticipating residence, or any combination of those
25		properties or residences shall disclose the existence of such
26		a waiver to any buyer or transferee before any sale or transfer

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1		of the property. If disclosure of the waiver occurs after the
2		buyer has made an offer to purchase the property, the seller
3		shall disclose the existence of the waiver before accepting
4		the buyer's offer and shall (1) allow the buyer an opportunity
5		to review the disclosure and (2) inform the buyer that the
6		buyer has the right to amend the buyer's offer.
7		(g) A county may not place any restriction on the
8		installation or use of a commercial wind energy facility or a
9		commercial solar energy facility unless it adopts an ordinance
10		that complies with this Section. A county may not establish
11		siting standards for supporting facilities that preclude
12		development of commercial wind energy facilities or commercial
13		solar energy facilities.
14		A request for siting approval or a special use permit for a
15		commercial wind energy facility or a commercial solar energy
16		facility, or modification of an approved siting or special use
17		permit, shall be approved if the request is in compliance with
18		the standards and conditions imposed in this Act, the zoning
19		ordinance adopted consistent with this Act Code, and the
20		conditions imposed under State and federal statutes and
21		regulations.
22		(h) A county may not adopt zoning regulations that
23		disallow, permanently or temporarily, commercial wind energy
24		facilities or commercial solar energy facilities from being
25		developed or operated in any district zoned to allow
26		agricultural or industrial uses.

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1		(i) (Blank). A county may not require permit application
2		fees for a commercial wind energy facility or commercial solar
3		energy facility that are unreasonable. All application fees
4		imposed by the county shall be consistent with fees for
5		projects in the county with similar capital value and cost.
6		(i-5) All siting approval or special use permit
7		application fees for a commercial wind energy facility or
8		commercial solar energy facility must be reasonable. Fees that
9		do not exceed $5,000 per each megawatt of nameplate capacity
10		of the energy facility, up to a maximum of $125,000, shall be
11		considered presumptively reasonable. A county may also require
12		reimbursement from the applicant for any reasonable expenses
13		incurred by the county in processing the siting approval or
14		special use permit application in excess of the maximum fee. A
15		siting approval or special use permit shall not be subject to
16		any time deadline to start construction or obtain a building
17		permit of less than 5 years from the date of siting approval or
18		special use permit approval. A county shall allow an applicant
19		to request an extension of the deadline based upon reasonable
20		cause for the extension request. The exemption shall not be
21		unreasonably withheld, conditioned, or denied.
22		(i-10) A county may require, for a commercial wind energy
23		facility or commercial solar energy facility, a single
24		building permit and a reasonable permit fee for the facility
25		which includes all supporting facilities. County building
26		permit fees for commercial wind energy facility or commercial

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1		solar energy facility that do not exceed $5,000 per each
2		megawatt of nameplate capacity of the energy facility, up to a
3		maximum of $75,000, shall be considered presumptively
4		reasonable. A county may also require reimbursement from the
5		applicant for any reasonable expenses incurred by the county
6		in processing the building permit in excess of the maximum
7		fee. A county may require an applicant, upon start of
8		construction of the facility, to maintain liability insurance
9		that is commercially reasonable and consistent with prevailing
10		industry standards for similar energy facilities.
11		(j) Except as otherwise provided in this Section, a county
12		shall not require standards for construction, decommissioning,
13		or deconstruction of a commercial wind energy facility or
14		commercial solar energy facility or related financial
15		assurances that are more restrictive than those included in
16		the Department of Agriculture's standard wind farm
17		agricultural impact mitigation agreement, template 81818, or
18		standard solar agricultural impact mitigation agreement,
19		version 8.19.19, as applicable and in effect on December 31,
20		2022. The amount of any decommissioning payment shall be in
21		accordance with the financial assurance required by those
22		agricultural impact mitigation agreements.
23		(j-5) A commercial wind energy facility or a commercial
24		solar energy facility shall file a farmland drainage plan with
25		the county and impacted drainage districts outlining how
26		surface and subsurface drainage of farmland will be restored

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1		during and following construction or deconstruction of the
2		facility. The plan is to be created independently by the
3		facility developer and shall include the location of any
4		potentially impacted drainage district facilities to the
5		extent this information is publicly available from the county
6		or the drainage district, plans to repair any subsurface
7		drainage affected during construction or deconstruction using
8		procedures outlined in the agricultural impact mitigation
9		agreement entered into by the commercial wind energy facility
10		owner or commercial solar energy facility owner, and
11		procedures for the repair and restoration of surface drainage
12		affected during construction or deconstruction. All surface
13		and subsurface damage shall be repaired as soon as reasonably
14		practicable.
15		(k) A county may not condition approval of a commercial
16		wind energy facility or commercial solar energy facility on a
17		property value guarantee and may not require a facility owner
18		to pay into a neighboring property devaluation escrow account.
19		(l) A county may require certain vegetative screening
20		between a surrounding a commercial wind energy facility or
21		commercial solar energy facility and nonparticipating
22		residences. A county but may not require earthen berms or
23		similar structures. Vegetative screening requirements shall be
24		commercially reasonable and limited in height at full maturity
25		to avoid reduction of the productive energy output of the
26		commercial solar energy facility. A county may not require

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1		vegetative screening to exceed 5 feet in height when first
2		installed or prior to commercial operation date. The screening
3		requirements shall take into account the size and location of
4		the facility, visibility from nonparticipating residences,
5		compatibility of native plant species, cost and feasibility of
6		installation and maintenance, and industry standards and best
7		practices for commercial solar energy facilities.
8		(m) A county may set blade tip height limitations for wind
9		towers in commercial wind energy facilities but may not set a
10		blade tip height limitation that is more restrictive than the
11		height allowed under a Determination of No Hazard to Air
12		Navigation by the Federal Aviation Administration under 14 CFR
13		Part 77.
14		(n) A county may require that a commercial wind energy
15		facility owner or commercial solar energy facility owner
16		provide:
17		(1) the results and recommendations from consultation
18		with the Illinois Department of Natural Resources that are
19		obtained through the Ecological Compliance Assessment Tool
20		(EcoCAT) or a comparable successor tool; and
21		(2) (blank). the results of the United States Fish and
22		Wildlife Service's Information for Planning and Consulting
23		environmental review or a comparable successor tool that
24		is consistent with (i) the "U.S. Fish and Wildlife
25		Service's Land-Based Wind Energy Guidelines" and (ii) any
26		applicable United States Fish and Wildlife Service solar

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1		wildlife guidelines that have been subject to public
2		review.
3		(o) A county may require a commercial wind energy facility
4		or commercial solar energy facility to adhere to the
5		recommendations provided by the Illinois Department of Natural
6		Resources in an EcoCAT natural resource review report under 17
7		Ill. Adm. Code Part 1075.
8		(p) A county may require a facility owner to:
9		(1) demonstrate avoidance of protected lands as
10		identified by the Illinois Department of Natural Resources
11		and the Illinois Nature Preserve Commission; or
12		(2) consider the recommendations of the Illinois
13		Department of Natural Resources for setbacks from
14		protected lands, including areas identified by the
15		Illinois Nature Preserve Commission.
16		(q) A county may require that a facility owner provide
17		evidence of consultation with the Illinois State Historic
18		Preservation Office to assess potential impacts on
19		State-registered historic sites under the Illinois State
20		Agency Historic Resources Preservation Act.
21		(r) To maximize community benefits, including, but not
22		limited to, reduced stormwater runoff, flooding, and erosion
23		at the ground mounted solar energy system, improved soil
24		health, and increased foraging habitat for game birds,
25		songbirds, and pollinators, a county may (1) require a
26		commercial solar energy facility owner to plant, establish,

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1		and maintain for the life of the facility vegetative ground
2		cover, consistent with the goals of the Pollinator-Friendly
3		Solar Site Act and (2) require the submittal of a vegetation
4		management plan that is in compliance with the agricultural
5		impact mitigation agreement in the application to construct
6		and operate a commercial solar energy facility in the county
7		if the vegetative ground cover and vegetation management plan
8		comply with the requirements of the underlying agreement with
9		the landowner or landowners where the facility will be
10		constructed.
11		No later than 90 days after January 27, 2023 (the
12		effective date of Public Act 102-1123), the Illinois
13		Department of Natural Resources shall develop guidelines for
14		vegetation management plans that may be required under this
15		subsection for commercial solar energy facilities. The
16		guidelines must include guidance for short-term and long-term
17		property management practices that provide and maintain native
18		and non-invasive naturalized perennial vegetation to protect
19		the health and well-being of pollinators.
20		(s) If a facility owner enters into a road use agreement
21		with the Illinois Department of Transportation, a road
22		district, or other unit of local government relating to a
23		commercial wind energy facility or a commercial solar energy
24		facility, the road use agreement shall require the facility
25		owner to be responsible for (i) the reasonable cost of
26		improving roads used by the facility owner to construct the

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1		commercial wind energy facility or the commercial solar energy
2		facility and (ii) the reasonable cost of repairing roads used
3		by the facility owner during construction of the commercial
4		wind energy facility or the commercial solar energy facility
5		so that those roads are in a condition that is safe for the
6		driving public after the completion of the facility's
7		construction. Roadways improved in preparation for and during
8		the construction of the commercial wind energy facility or
9		commercial solar energy facility shall be repaired and
10		restored to the improved condition at the reasonable cost of
11		the developer if the roadways have degraded or were damaged as
12		a result of construction-related activities.
13		The road use agreement shall not require the facility
14		owner to pay costs, fees, or charges for road work that is not
15		specifically and uniquely attributable to the construction of
16		the commercial wind energy facility or the commercial solar
17		energy facility. No road district or other unit of local
18		government may request or require permit fees, fines, or other
19		payment obligations as a requirement for a road use agreement
20		with a facility owner unless the amount of the reasonable
21		permit fee or payment is equivalent to the amount of actual
22		expenses incurred by the road district or other unit of local
23		government for negotiating, executing, constructing, or
24		implementing the road use agreement. The road use agreement
25		shall not require any road work to be performed by or paid for
26		by the facility owner that is not specifically and uniquely

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1		attributable to the road improvements required for the
2		construction of the commercial wind energy facility or the
3		commercial solar energy facility or the restoration of the
4		roads used by the facility owner during construction-related
5		activities. Road-related fees, permit fees, or other charges
6		imposed by the Illinois Department of Transportation, a road
7		district, or other unit of local government under a road use
8		agreement with the facility owner shall be reasonably related
9		to the cost of administration of the road use agreement.
10		(s-5) The facility owner shall also compensate landowners
11		for crop losses or other agricultural damages resulting from
12		damage to the drainage system caused by the construction of
13		the commercial wind energy facility or the commercial solar
14		energy facility. The commercial wind energy facility owner or
15		commercial solar energy facility owner shall repair or pay for
16		the repair of all damage to the subsurface drainage system
17		caused by the construction of the commercial wind energy
18		facility or the commercial solar energy facility in accordance
19		with the agriculture impact mitigation agreement requirements
20		for repair of drainage. The commercial wind energy facility
21		owner or commercial solar energy facility owner shall repair
22		or pay for the repair and restoration of surface drainage
23		caused by the construction or deconstruction of the commercial
24		wind energy facility or the commercial solar energy facility
25		as soon as reasonably practicable.
26		(t) Notwithstanding any other provision of law, a facility

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1		owner with siting approval from a county to construct a
2		commercial wind energy facility or a commercial solar energy
3		facility is authorized to cross or impact a drainage system,
4		including, but not limited to, drainage tiles, open drainage
5		ditches, culverts, and water gathering vaults, owned or under
6		the control of a drainage district under the Illinois Drainage
7		Code without obtaining prior agreement or approval from the
8		drainage district in accordance with the farmland drainage
9		plan required by subsection (j-5).
10		(u) The amendments to this Section adopted in Public Act
11		102-1123 do not apply to: (1) an application for siting
12		approval or for a special use permit for a commercial wind
13		energy facility or commercial solar energy facility if the
14		application was submitted to a unit of local government before
15		January 27, 2023 (the effective date of Public Act 102-1123);
16		(2) a commercial wind energy facility or a commercial solar
17		energy facility if the facility owner has submitted an
18		agricultural impact mitigation agreement to the Department of
19		Agriculture before January 27, 2023 (the effective date of
20		Public Act 102-1123); or (3) a commercial wind energy or
21		commercial solar energy development on property that is
22		located within an enterprise zone certified under the Illinois
23		Enterprise Zone Act, that was classified as industrial by the
24		appropriate zoning authority on or before January 27, 2023,
25		and that is located within 4 miles of the intersection of
26		Interstate 88 and Interstate 39; or (4) a commercial wind

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1		energy or commercial solar energy development on property in
2		Madison County that is located within the area that has as its
3		northern boundary the portion of Drexelius Road that is
4		between the intersection of Drexelius Road and Wolf Road and
5		the intersection of Drexelius Road and Fosterburg Road, that
6		has as its eastern boundary the portion of Fosterburg Road
7		that is between the intersection of Fosterburg Road and
8		Drexelius Road and the intersection of Fosterburg Road and
9		Wolf Road, and that has as its southern and western boundaries
10		the portion of Wolf Road that is between the intersection of
11		Fosterburg Road and Wolf Road and the intersection of
12		Drexelius Road and Wolf Road.
13		(Source: P.A. 102-1123, eff. 1-27-23; 103-81, eff. 6-9-23;
14		103-580, eff. 12-8-23; revised 7-29-24.)
15		(55 ILCS 5/5-12024 new)
16		Sec. 5-12024. Energy storage systems.
17		(a) As used in this Section:
18		"Energy storage system" means a facility with an aggregate
19		energy capacity that is greater than 1,000 kilowatts and that
20		is capable of absorbing energy and storing it for use at a
21		later time, including, but not limited to, electrochemical and
22		electromechanical technologies. "Energy storage system" does
23		not include technologies that require combustion. "Energy
24		storage system" also does not include energy storage systems
25		associated with commercial solar energy facilities or

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1		commercial wind energy facilities as defined in Section
2		5-12020.
3		"Excused service interruption" means any period during
4		which an energy storage system does not store or discharge
5		electricity and that is planned or reasonably foreseeable for
6		standard commercial operation, including any unavailability
7		caused by a buyer; storage capacity tests; system emergencies;
8		curtailments, including curtailment orders; transmission
9		system outages; compliance with any operating restriction;
10		serial defects; and planned outages.
11		"Facility owner" means (i) a person with a direct
12		ownership interest in an energy storage system, regardless of
13		whether the person is involved in acquiring the necessary
14		rights, permits, and approvals or otherwise planning for the
15		construction and operation of the facility and (ii) a person
16		who, at the time the facility is being developed, is acting as
17		a developer of the facility by acquiring the necessary rights,
18		permits, and approvals or by planning for the construction and
19		operation of the facility, regardless of whether the person
20		will own or operate the facility.
21		"Force majeure" means any event or circumstance that
22		delays or prevents an energy storage system from timely
23		performing all or a portion of its commercial operations if
24		the act or event, despite the exercise of commercially
25		reasonable efforts, cannot be avoided by and is beyond the
26		reasonable control, whether direct or indirect, of, and

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1		without the fault or negligence of, a facility owner or
2		operator or any of its assignees. "Force majeure" includes,
3		but is not limited to:
4		(1) fire, flood, tornado, or other natural disasters
5		or acts of God;
6		(2) war, civil strife, terrorist attack, or other
7		similar acts of violence;
8		(3) unavailability of materials, equipment, services,
9		or labor, including unavailability due to global supply
10		chain shortages;
11		(4) utility or energy shortages or acts or omissions
12		of public utility providers;
13		(5) any delay resulting from a pandemic, epidemic, or
14		other public health emergency or related restrictions; and
15		(6) litigation or a regulatory proceeding regarding a
16		facility.
17		"NFPA" means the National Fire Protection Association.
18		"Nonparticipating property" means real property that is
19		not a participating property.
20		"Nonparticipating residence" means a residence that is
21		located on nonparticipating property and that exists and is
22		occupied on the date that the application for a permit to
23		develop an energy storage system is filed with the county.
24		"Occupied community building" means a school, place of
25		worship, day care facility, public library, or community
26		center that is occupied on the date that the application for a

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1		permit to develop an energy storage system is filed with the
2		county in which the building is located.
3		"Participating property" means real property that is the
4		subject of a written agreement between a facility owner and
5		the owner of the real property and that provides the facility
6		owner an easement, option, lease, or license to use the real
7		property for the purpose of constructing an energy storage
8		system or supporting facilities.
9		"Protected lands" means real property that is: (i) subject
10		to a permanent conservation right consistent with the Real
11		Property Conservation Rights Act; or (ii) registered or
12		designated as a nature preserve, buffer, or land and water
13		reserve under the Illinois Natural Areas Preservation Act.
14		"Supporting facilities" means the transmission lines,
15		substations, switchyard, access roads, meteorological towers,
16		storage containers, and equipment associated with the
17		generation, storage, and dispatch of electricity by an energy
18		storage system.
19		(b) Notwithstanding any other provision of law, if a
20		county has formed a zoning commission and adopted formal
21		zoning under Section 5-12007, then a county may establish
22		standards for energy storage systems in areas of the county
23		that are not within the zoning jurisdiction of a municipality.
24		The standards may include all of the requirements specified in
25		this Section but may not include requirements for energy
26		storage systems that are more restrictive than specified in

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1		this Section or requirements that are not specified in this
2		Section.
3		(c) A county may require the energy storage facility to
4		comply with the version of NFPA 855 "Standard for the
5		Installation of Stationary Energy Storage Systems" in effect
6		on the effective date of this amendatory Act or any successor
7		standard issued by the NFPA in effect on the date of siting or
8		special use permit approval. A county may not include
9		requirements for energy storage systems that are more
10		restrictive than NFPA 855 "Standard for the Installation of
11		Stationary Energy Storage Systems" unless required by this
12		Section.
13		(d) If a county has elected to establish standards under
14		subsection (b), then the zoning board of appeals for the
15		county shall hold at least one public hearing before the
16		county grants (i) siting approval or a special use permit for
17		an energy storage system or (ii) modification of an approved
18		siting or special use permit. The public hearing shall be
19		conducted in accordance with the Open Meetings Act and shall
20		conclude not more than 60 days after the filing of the
21		application for the facility. The county shall allow
22		interested parties to a special use permit an opportunity to
23		present evidence and to cross-examine witnesses at the
24		hearing, but the county may impose reasonable restrictions on
25		the public hearing, including reasonable time limitations on
26		the presentation of evidence and the cross-examination of

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1		witnesses. The county shall also allow public comment at the
2		public hearing in accordance with the Open Meetings Act. The
3		county shall make its siting and permitting decisions not more
4		than 30 days after the conclusion of the public hearing.
5		Notice of the hearing shall be published in a newspaper of
6		general circulation in the county.
7		(e) A county with an existing zoning ordinance in conflict
8		with this Section shall amend that zoning ordinance to comply
9		with this Section within 120 days after the effective date of
10		this amendatory Act of the 104th General Assembly.
11		(f) A county shall require an energy storage system to be
12		sited as follows, with setback distances measured from the
13		nearest edge of the nearest battery or other electrochemical
14		or electromechanical enclosure:
15		Setback Description           Setback Distance
16		Occupied Community            150 feet from the nearest
17		Buildings and                 point of the outside wall of
18		Nonparticipating Residences   the occupied community building
19		or nonparticipating residence
20		Boundary Lines of             50 feet to the nearest point
21		Occupied Community            on the property line of
22		Buildings and                 the occupied community building
23		Nonparticipating Residences   or nonparticipating property

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1		Public Road Rights-of-Way     50 feet from the nearest edge
2		of the right-of-way
3		(2) A county shall also require an energy storage
4		system to be sited so that the facility's perimeter is
5		enclosed by fencing having a height of at least 7 feet and
6		no more than 25 feet.
7		This Section does not exempt or excuse compliance with
8		electric facility clearances approved or required by the
9		National Electrical Code, the National Electrical Safety Code,
10		the Illinois Commerce Commission, the Federal Energy
11		Regulatory Commission, and their designees or successors.
12		(g) A county may not set a sound limitation for energy
13		storage systems that is more restrictive than the sound
14		limitations established by the Illinois Pollution Control
15		Board under 35 Ill. Adm. Code Parts 900, 901, and 910. After
16		commercial operation, a county may require the facility owner
17		to provide, not more than once, octave band sound pressure
18		level measurements from a reasonable number of sampled
19		locations at the perimeter of the energy storage system to
20		demonstrate compliance with this Section.
21		(h) The provisions set forth in subsection (f) may be
22		waived subject to the written consent of the owner of each
23		affected nonparticipating property or nonparticipating
24		residence.
25		(i) A county may not place any restriction on the

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1		installation or use of an energy storage system unless it has
2		formed a zoning commission and adopted formal zoning under
3		Section 5-12007 and adopts an ordinance that complies with
4		this Section. A county may not establish siting standards for
5		supporting facilities that preclude development of an energy
6		storage system.
7		(j) A request for siting approval or a special use permit
8		for an energy storage system, or modification of an approved
9		siting approval or special use permit, shall be approved if
10		the request complies with the standards and conditions imposed
11		in this Code, the zoning ordinance adopted consistent with
12		this Section, and other State and federal statutes and
13		regulations. The siting approval or special use permit
14		approved by the county shall grant the facility owner a period
15		of at least 3 years after county approval to obtain a building
16		permit or commence construction of the energy storage system,
17		before the siting approval or special use permit may become
18		subject to revocation by the county. Facility owners may be
19		granted an extension on obtaining building permits or
20		commencing constructing upon a showing of good cause. A
21		facility owner's request for an extension may not be
22		unreasonably withheld, conditioned, or denied.
23		(k) A county may not adopt zoning regulations that
24		disallow, permanently or temporarily, an energy storage system
25		from being developed or operated in any district zones to
26		allow agricultural or industrial uses.

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1		(l) A facility owner shall file a farmland drainage plan
2		with the county and impacted drainage districts that outlines
3		how surface and subsurface drainage of farmland will be
4		restored during and following the construction or
5		deconstruction of the energy storage system. The plan shall be
6		created independently by the facility owner and shall include
7		the location of any potentially impacted drainage district
8		facilities to the extent the information is publicly available
9		from the county or the drainage district and plans to repair
10		any subsurface drainage affected during construction or
11		deconstruction using procedures outlined in the
12		decommissioning plan. All surface and subsurface damage shall
13		be repaired as soon as reasonably practicable.
14		(m) A facility owner shall compensate landowners for crop
15		losses or other agricultural damages resulting from damage to
16		a drainage system caused by the construction of an energy
17		storage system. The facility owner shall repair or pay for the
18		repair of all damage to the subsurface drainage system caused
19		by the construction of the energy storage system. The facility
20		owner shall repair or pay for the repair and restoration of
21		surface drainage caused by the construction or deconstruction
22		of the energy storage facility as soon as reasonably
23		practicable.
24		(n) County siting approval or special use permit
25		application fees for an energy storage system shall not exceed
26		the lesser of (i) $5,000 per each megawatt of nameplate

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1		capacity of the energy storage system or (ii) $50,000.
2		(o) The county may require a facility owner to provide a
3		decommissioning plan to the county. The decommissioning plan
4		may include all requirements for decommissioning plans in NFPA
5		855 and may also require the facility owner to:
6		(1) state how the energy storage system will be
7		decommissioned, including removal to a depth of 3 feet of
8		all structures that have no ongoing purpose and all debris
9		and restoration of the soil and any vegetation to a
10		condition as close as reasonably practicable to the soil's
11		and vegetation's preconstruction condition within 18
12		months of the end of project life or facility abandonment;
13		(2) include provisions related to commercially
14		reasonable efforts to reuse or recycle of equipment and
15		components associated with the commercial offsite energy
16		storage system;
17		(3) include financial assurance in the form of a
18		reclamation or surety bond or other commercially available
19		financial assurance that is acceptable to the county, with
20		the county or participating property owner as beneficiary.
21		The amount of the financial assurance shall not be more
22		than the estimated cost of decommissioning the energy
23		facility, after deducting salvage value, as calculated by
24		a professional engineer licensed to practice engineering
25		in this State with expertise in preparing decommissioning
26		estimates, retained by the applicant. The financial

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1		assurance shall be provided to the county incrementally as
2		follows:
3		(A) 25% before the start of full commercial
4		operation;
5		(B) 50% before the start of the 5th year of
6		commercial operation; and
7		(C) 100% by the start of the tenth year of
8		commercial operation;
9		(4) update the amount of the financial assurance not
10		more than every 5 years for the duration of commercial
11		operations. The amount shall be calculated by a
12		professional engineer licensed to practice engineering in
13		this State with expertise in decommissioning, hired by the
14		facility owner; and
15		(5) decommission the energy storage system, in
16		accordance with an approved decommissioning plan, within
17		18 months after abandonment. An energy storage system that
18		has not stored electrical energy for 12 consecutive months
19		or that fails, for a period of 6 consecutive months, to pay
20		a property owner who is party to a written agreement,
21		including, but not limited to, an easement, option, lease,
22		or license under the terms of which an energy storage
23		system is constructed on the property, amounts owed in
24		accordance with the written agreement shall be considered
25		abandoned, except when the inability to store energy is
26		the result of an event of force majeure or excused service

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1		interruption.
2		(p) A county may not condition approval of an energy
3		storage system on a property value guarantee and may not
4		require a facility owner to pay into a neighboring property
5		devaluation escrow account.
6		(q) A county may require that a facility owner provide the
7		results and recommendations from consultation with the
8		Department of Natural Resources that are obtained through the
9		Ecological Compliance Assessment Tool (EcoCAT) or a comparable
10		successor tool.
11		(r) A county may require an energy storage system to
12		adhere to the recommendations provided by the Department of
13		Natural Resources in an Agency Action Report under 17 Ill.
14		Adm. 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
24		evidence of consultation with the Illinois Historic
25		Preservation Division to assess potential impacts on
26		State-registered historic sites under the Illinois State

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1		Agency Historic Resources Preservation Act.
2		(u) A county may require that an application for siting
3		approval or special use permit include the following
4		information 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
14		from undertaking periodic augmentation to maintain the
15		approximate original capacity of the energy storage system. A
16		county may not require renewed or additional siting approval
17		or special use permit approval of periodic augmentation to
18		maintain the approximate original capacity of the energy
19		storage system.
20		(w) A county that issues a building permit for energy
21		storage systems shall review and process building permit
22		applications within 60 days after receipt of the building
23		permit application. If a county does not grant or deny the
24		building permit application within 60 days, the building
25		permit shall be deemed granted. If a county denies a building
26		permit application, it shall specify the reason for the denial

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1		in writing as part of its denial.
2		(x) A county may require a single building permit and a
3		reasonable permit fee for the facility which includes all
4		supporting facilities. A county building permit fee for an
5		energy storage system that does not exceed the lesser of (i)
6		$5,000 per each megawatt of nameplate capacity of the energy
7		storage system or (ii) $50,000 shall be considered
8		presumptively reasonable. A county may require that the
9		application for building permit contain:
10		(1) an electrical diagram detailing the battery energy
11		storage system layout, associated components, and
12		electrical interconnection methods, with all National
13		Electrical Code compliant disconnects and overcurrent
14		devices; and
15		(2) an equipment specification sheet.
16		(y) A county may require the facility owner to submit to
17		the county prior to the facility's commercial operation a
18		commissioning report meeting the requirements of NFPA 855
19		Sections 4.2.4, 6.1.3, and 6.1.5.5, as published in 2023, or
20		the applicable Sections in the most recent version of NFPA
21		855.
22		(z) A county may require the facility owner to submit to
23		the county prior to the facility's commercial operation a
24		hazard mitigation analysis meeting the requirements of NFPA
25		855 Section 4.4 or the applicable Sections in the most recent
26		version of NFPA 855.

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1		(aa) A county may require the facility owner to submit to
2		the county an emergency operations plan meeting the
3		requirements of NFPA 855 Section 4.3.2.1.4, published in 2023,
4		or applicable Sections in the most recent version of NFPA 855,
5		prior to commercial operation.
6		(bb) A county may require a warning that complies with
7		requirements in NFPA 855 Section 4.7.4, published in 2023, or
8		applicable sections in the most recent version of NFPA 855.
9		(cc) A county may require the energy storage system to
10		adhere to the principles for responsible outdoor lighting
11		provided by the International Dark-Sky Association and shall
12		limit outdoor lighting to that which is minimally required for
13		safety and operational purposes. Any outdoor lighting shall be
14		reasonably shielded and downcast from all residences and
15		adjacent properties.
16		(dd) This Section does not exempt compliance with fire and
17		safety standards and guidance established for the installation
18		of lithium-ion battery energy storage systems set by the NFPA.
19		(ee) Prior to commencement of commercial operation, the
20		facility owner shall offer to provide training for local fire
21		departments and emergency responders in accordance with the
22		facility emergency operations plan. A copy of the emergency
23		operations plan shall be given to the facility owner, the
24		local fire department, and emergency responders. All batteries
25		integrated within an energy storage system shall be listed
26		under the UL 1973 Standard. All batteries integrated within an

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1		energy storage system shall be listed in accordance with UL
2		9540 Standard, either from the manufacturer or by a field
3		evaluation.
4		(ff) If a facility owner enters into a road use agreement
5		with the Department of Transportation, a road district, or
6		other unit of local government relating to an energy storage
7		system, then the road use agreement shall require the facility
8		owner to be responsible for (i) the reasonable cost of
9		improving, if necessary, roads used by the facility owner to
10		construct the energy storage system and (ii) the reasonable
11		cost of repairing roads used by the facility owner during
12		construction of the energy storage system so that those roads
13		are in a condition that is safe for the driving public after
14		the completion of the facility's construction. A roadway
15		improved in preparation for and during the construction of the
16		energy storage system shall be repaired and restored to the
17		improved condition at the reasonable cost of the developer if
18		the roadways have degraded or were damaged as a result of
19		construction-related activities.
20		The road use agreement shall not require the facility
21		owner to pay costs, fees, or charges for road work that is not
22		specifically and uniquely attributable to the construction of
23		the energy storage system. No road district or other unit of
24		local government may request or require a fine, permit fee, or
25		other payment obligation as a requirement for a road use
26		agreement with a facility owner unless the amount of the fine,

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1		permit fee, or other payment obligation is equivalent to the
2		amount of actual expenses incurred by the road district or
3		other unit of local government for negotiating, executing,
4		constructing, or implementing the road use agreement. The road
5		use agreement shall not require the facility owner to perform
6		or pay for any road work that is unrelated to the road
7		improvements required for the construction of the commercial
8		wind energy facility or the commercial solar energy facility
9		or the restoration of the roads used by the facility owner
10		during construction-related activities.
11		(gg) The provisions of this amendatory Act of the 104th
12		General Assembly do not apply to an application for siting
13		approval or special use permit for an energy storage system if
14		the application was submitted to a county before the effective
15		date of this amendatory Act of the 104th General Assembly.
16		(55 ILCS 5/Art. 5 Div. 5-46 heading new)
17		Division 5-46. Solar Bill of Rights
18		(55 ILCS 5/5-46005 new)
19		Sec. 5-46005. Definitions. As used in this Division:
20		"Low-voltage solar-powered device" means a piece of
21		equipment designed for a particular purpose, including, but
22		not limited to, doorbells, security systems, and illumination
23		equipment, powered by a solar collector operating at less than
24		50 volts, and located:

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1		(1) entirely within the lot or parcel owned by the
2		property owner; or
3		(2) within a common area without being permanently
4		attached to common property.
5		"Solar collector" means:
6		(1) an assembly, structure, or design, including
7		passive elements, used for gathering, concentrating, or
8		absorbing direct and indirect solar energy and specially
9		designed for holding a substantial amount of useful
10		thermal energy and to transfer that energy to a gas,
11		solid, or liquid or to use that energy directly;
12		(2) a mechanism that absorbs solar energy and converts
13		it into electricity;
14		(3) a mechanism or process used for gathering solar
15		energy through wind or thermal gradients; or
16		(4) a component used to transfer thermal energy to a
17		gas, solid, or liquid, or to convert it into electricity.
18		"Solar energy" means radiant energy received from the sun
19		at wavelengths suitable for heat transfer, photosynthetic use,
20		or photovoltaic use.
21		"Solar energy system" means:
22		(1) a complete assembly, structure, or design of a
23		solar collector or a solar storage mechanism that uses
24		solar energy for generating electricity or for heating or
25		cooling gases, solids, liquids, or other materials; and
26		(2) the design, materials, or elements of a system and

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1		its maintenance, operation, and labor components, and the
2		necessary components, if any, of supplemental conventional
3		energy systems designed or constructed to interface with a
4		solar energy system.
5		"Solar storage mechanism" means equipment or elements,
6		such as piping and transfer mechanisms, containers, heat
7		exchangers, batteries, or controls thereof and gases, solids,
8		liquids, or combinations thereof, that are utilized for
9		storing solar energy, gathered by a solar collector, for
10		subsequent use.
11		(55 ILCS 5/5-46010 new)
12		Sec. 5-46010. Prohibitions. Notwithstanding any provision
13		of this Code or other provision of law, the adoption of any
14		ordinance or resolution or the exercise of any power by a
15		county that prohibits or has the effect of prohibiting the
16		installation of a solar energy system or low-voltage
17		solar-powered devices is expressly prohibited.
18		(55 ILCS 5/5-46020 new)
19		Sec. 5-46020. Costs; attorney's fees. In any litigation
20		arising under this Division or involving the application of
21		this Division, the prevailing party shall be entitled to costs
22		and reasonable attorney's fees.
23		(55 ILCS 5/5-46025 new)

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1		Sec. 5-46025. Applicability.
2		(a) As used in this Section, "shared roof" means any roof
3		that (i) serves more than one unit, including, but not limited
4		to, a contiguous roof serving adjacent units, or (ii) is part
5		of the common elements or common area of a unit.
6		(b) This Division shall not apply to any building that:
7		(1) is greater than 60 feet in height; or
8		(2) has a shared roof.
9		(c) Notwithstanding subsection (b) of this Section, this
10		Division shall apply to any building with a shared roof:
11		(1) where the solar energy system is located entirely
12		within that portion of the shared roof that is owned and
13		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		Section 90-30. The Illinois Municipal Code is amended by
19		adding Division 15.5 as follows:
20		(65 ILCS 5/Art. 11 Div. 15.5 heading new)
21		Division 15.5. Solar Bill of Rights
22		(65 ILCS 5/11-15.5-5 new)
23		Sec. 11-15.5-5. Definitions. As used in this Division:

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1		"Low-voltage solar-powered device" means a piece of
2		equipment designed for a particular purpose, including, but
3		not limited to, doorbells, security systems, and illumination
4		equipment, powered by a solar collector operating at less than
5		50 volts, and located:
6		(1) entirely within the lot or parcel owned by the
7		property owner; or
8		(2) within a common area without being permanently
9		attached to common property.
10		"Solar collector" means:
11		(1) an assembly, structure, or design, including
12		passive elements, used for gathering, concentrating, or
13		absorbing direct and indirect solar energy and specially
14		designed for holding a substantial amount of useful
15		thermal energy and to transfer that energy to a gas,
16		solid, or liquid or to use that energy directly;
17		(2) a mechanism that absorbs solar energy and converts
18		it into electricity;
19		(3) a mechanism or process used for gathering solar
20		energy through wind or thermal gradients; or
21		(4) a component used to transfer thermal energy to a
22		gas, solid, or liquid, or to convert it into electricity.
23		"Solar energy" means radiant energy received from the sun
24		at wavelengths suitable for heat transfer, photosynthetic use,
25		or photovoltaic use.
26		"Solar energy system" means:

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1		(1) a complete assembly, structure, or design of a
2		solar collector or a solar storage mechanism that uses
3		solar energy for generating electricity or for heating or
4		cooling gases, solids, liquids, or other materials; and
5		(2) the design, materials, or elements of a system and
6		its maintenance, operation, and labor components, and the
7		necessary components, if any, of supplemental conventional
8		energy systems designed or constructed to interface with a
9		solar energy system.
10		"Solar storage mechanism" means equipment or elements,
11		such as piping and transfer mechanisms, containers, heat
12		exchangers, batteries, or controls thereof and gases, solids,
13		liquids, or combinations thereof, that are utilized for
14		storing solar energy, gathered by a solar collector, for
15		subsequent use.
16		(65 ILCS 5/11-15.5-10 new)
17		Sec. 11-15.5-10. Prohibitions. Notwithstanding any
18		provision of this Code or other provision of law, the adoption
19		of any ordinance or resolution or the exercise of any power, by
20		municipality that prohibits or has the effect of prohibiting
21		the installation of a solar energy system or low-voltage
22		solar-powered devices is expressly prohibited. Municipalities
23		that own local electric distribution systems may adopt and
24		implement reasonable policies, consistent with Section 17-900
25		of the Public Utilities Act, regarding the interconnection and

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1		use of solar energy systems.
2		(65 ILCS 5/11-15.5-20 new)
3		Sec. 11-15.5-20. Costs; attorney's fees. In any litigation
4		arising under this Division or involving the application of
5		this Division, the prevailing party shall be entitled to costs
6		and reasonable attorney's fees.
7		(65 ILCS 5/11-15.5-25 new)
8		Sec. 11-15.5-25. Applicability.
9		(a) As used in this Section, "shared roof" means any roof
10		that (i) serves more than one unit, including, but not limited
11		to, a contiguous roof serving adjacent units, or (ii) is part
12		of the common elements or common area of a unit.
13		(b) This Division shall not apply to any building that:
14		(1) is greater than 60 feet in height; or
15		(2) has a shared roof.
16		(c) Notwithstanding subsection (b) of this Section, this
17		Division shall apply to any building with a shared roof:
18		(1) where the solar energy system is located entirely
19		within that portion of the shared roof owned and
20		maintained by the property owner;
21		(2) where all property owners sharing the shared roof
22		are in agreement to install a solar energy system; or
23		(3) to the extent this Division applies to low-voltage
24		solar-powered devices.

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1		Section 90-35. The Public Utilities Act is amended by
2		changing Sections 7-102, 8-103B, 8-104, 8-512, 9-229,
3		16-107.5, 16-107.6, 16-108, 16-108.19, 16-108.30, 16-111.5,
4		16-111.7, 16-115A, 16-119A, and 17-900 and by adding Sections
5		8-101.1, 8-513, 16-105.17, 16-107.8, 16-107.9, 16-126.2,
6		16-145, 16-201, 16-202, 20-140, 20-145, and Article 23 as
7		follows:
8		(220 ILCS 5/7-102)  (from Ch. 111 2/3, par. 7-102)
9		Sec. 7-102. Transactions requiring Commission approval.
10		(A) Unless the consent and approval of the Commission is
11		first obtained or unless such approval is waived by the
12		Commission or is exempted in accordance with the provisions of
13		this Section or of any other Section of this Act:
14		(a) No 2 or more public utilities may enter into
15		contracts with each other that will enable such public
16		utilities to operate their lines or plants in connection
17		with each other.
18		(b) No public utility may purchase, lease, or in any
19		other manner acquire control, direct or indirect, over the
20		franchises, licenses, permits, plants, equipment, business
21		or other property of any other public utility.
22		(c) No public utility may assign, transfer, lease,
23		mortgage, sell (by option or otherwise), or otherwise
24		dispose of or encumber the whole or any part of its

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

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1		any of its moneys, property or other resources in or to any
2		business or enterprise which is not, prior to such use,
3		appropriation or diversion essentially and directly
4		connected with or a proper and necessary department or
5		division of the business of such public utility; provided
6		that this subsection shall not be construed as modifying
7		subsections (a) through (e) of this Section.
8		(h) No public utility may, directly or indirectly,
9		invest, loan or advance, or permit to be invested, loaned
10		or advanced any of its moneys, property or other resources
11		in, for, in behalf of or to any other person, firm, trust,
12		group, association, company or corporation whatsoever,
13		except that no consent or approval by the Commission is
14		necessary for the purchase of stock in development credit
15		corporations organized under the Illinois Development
16		Credit Corporation Act, providing that no such purchase
17		may be made hereunder if, as a result of such purchase, the
18		cumulative purchase price of all such shares owned by the
19		utility would exceed one-fiftieth of one per cent of the
20		utility's gross operating revenue for the preceding
21		calendar year.
22		(B) Any public utility may present to the Commission for
23		approval options or contracts to sell or lease real property,
24		notwithstanding that the value of the property under option
25		may have changed between the date of the option and the
26		subsequent date of sale or lease. If the options or contracts

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1		are approved by the Commission, subsequent sales or leases in
2		conformance with those options or contracts may be made by the
3		public utility without any further action by the Commission.
4		If approval of the options or contracts is denied by the
5		Commission, the options or contracts are void and any
6		consideration theretofore paid to the public utility must be
7		refunded within 30 days following disapproval of the
8		application.
9		(C) The proceedings for obtaining the approval of the
10		Commission provided for in this Section shall be as follows:
11		There shall be filed with the Commission a petition, joint or
12		otherwise, as the case may be, signed and verified by the
13		president, any vice president, secretary, treasurer,
14		comptroller, general manager, or chief engineer of the
15		respective companies, or by the person or company, as the case
16		may be, clearly setting forth the object and purposes desired,
17		and setting forth the full and complete terms of the proposed
18		assignment, transfer, lease, mortgage, purchase, sale, merger,
19		consolidation, contract or other transaction, as the case may
20		be. Upon the filing of such petition, the Commission shall, if
21		it deems necessary, fix a time and place for the hearing
22		thereon. After such hearing, or in case no hearing is
23		required, if the Commission is satisfied that such petition
24		should reasonably be granted, and that the public will be
25		convenienced thereby, the Commission shall make such order in
26		the premises as it may deem proper and as the circumstances may

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1		require, attaching such conditions as it may deem proper, and
2		thereupon it shall be lawful to do the things provided for in
3		such order. The Commission shall impose such conditions as
4		will protect the interest of minority and preferred
5		stockholders.
6		(D) The Commission shall have power by general rules
7		applicable alike to all public utilities, other than electric
8		and gas public utilities, affected thereby to waive the filing
9		and necessity for approval of the following: (a) sales of
10		property involving a consideration of not more than $300,000
11		for utilities with gross revenues in excess of $50,000,000
12		annually and a consideration of not more than $100,000 for all
13		other utilities; (b) leases, easements and licenses involving
14		a consideration or rental of not more than $30,000 per year for
15		utilities with gross revenues in excess of $50,000,000
16		annually and a consideration or rental of not more than
17		$10,000 per year for all other utilities; (c) leases of office
18		building space not required by the public utility in rendering
19		service to the public; (d) the temporary leasing, lending or
20		interchanging of equipment in the ordinary course of business
21		or in case of an emergency; and (e) purchase-money mortgages
22		given by a public utility in connection with the purchase of
23		tangible personal property where the total obligation to be
24		secured shall be payable within a period not exceeding one
25		year. However, if the Commission, after a hearing, finds that
26		any public utility to which such rule is applicable is abusing

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1		or has abused such general rule and thereby is evading
2		compliance with the standard established herein, the
3		Commission shall have power to require such public utility to
4		thereafter file and receive the Commission's approval upon all
5		such transactions as described in this Section, but such
6		general rule shall remain in full force and effect as to all
7		other public utilities to which such rule is applicable.
8		(E) The filing of, and the consent and approval of the
9		Commission for, any assignment, transfer, lease, mortgage,
10		purchase, sale, merger, consolidation, contract or other
11		transaction by an electric or gas public utility with gross
12		revenues in all jurisdictions of $250,000,000 or more annually
13		involving a sale price or annual consideration in an amount of
14		$5,000,000 or less shall not be required. The Commission shall
15		also have the authority, on petition by an electric or gas
16		public utility with gross revenues in all jurisdictions of
17		$250,000,000 or more annually, to establish by order higher
18		thresholds than the foregoing for the requirement of approval
19		of transactions by the Commission pursuant to this Section for
20		the electric or gas public utility, but no greater than 1% of
21		the electric or gas public utility's average total gross
22		utility plant in service in the case of sale, assignment or
23		acquisition of property, or 2.5% of the electric or gas public
24		utility's total revenue in the case of other sales price or
25		annual consideration, in each case based on the preceding
26		calendar year, and subject to the power of the Commission,

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1		after notice and hearing, to further revise those thresholds
2		at a later date. In addition to the foregoing, the Commission
3		shall have power by general rules applicable alike to all
4		electric and gas public utilities affected thereby to waive
5		the filing and necessity for approval of the following: (a)
6		sales of property involving a consideration of $100,000 or
7		less for electric and gas utilities with gross revenues in all
8		jurisdictions of less than $250,000,000 annually; (b) leases,
9		easements and licenses involving a consideration or rental of
10		not more than $10,000 per year for electric and gas utilities
11		with gross revenues in all jurisdictions of less than
12		$250,000,000 annually; (c) leases of office building space not
13		required by the electric or gas public utility in rendering
14		service to the public; (d) the temporary leasing, lending or
15		interchanging of equipment in the ordinary course of business
16		or in the case of an emergency; and (e) purchase-money
17		mortgages given by an electric or gas public utility in
18		connection with the purchase of tangible personal property
19		where the total obligation to be secured shall be payable
20		within a period of one year or less. However, if the
21		Commission, after a hearing, finds that any electric or gas
22		public utility is abusing or has abused such general rule and
23		thereby is evading compliance with the standard established
24		herein, the Commission shall have power to require such
25		electric or gas public utility to thereafter file and receive
26		the Commission's approval upon all such transactions as

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1		described in this Section and not exempted pursuant to the
2		first sentence of this paragraph or to subsection (g) of
3		Section 16-111 of this Act, but such general rule shall remain
4		in full force and effect as to all other electric and gas
5		public utilities.
6		Every assignment, transfer, lease, mortgage, sale or other
7		disposition or encumbrance of the whole or any part of the
8		franchises, licenses, permits, plant, equipment, business or
9		other property of any public utility, or any merger or
10		consolidation thereof, and every contract, purchase of stock,
11		or other transaction referred to in this Section and not
12		exempted in accordance with the provisions of the immediately
13		preceding paragraph of this Section, made otherwise than in
14		accordance with an order of the Commission authorizing the
15		same, except as provided in this Section, shall be void. The
16		provisions of this Section shall not apply to any transactions
17		by or with a political subdivision or municipal corporation of
18		this State.
19		(F) The provisions of this Section do not apply to the
20		purchase or sale of emission allowances created under and
21		defined in Title IV of the federal Clean Air Act Amendments of
22		1990 (P.L. 101-549), as amended.
23		(Source: P.A. 90-561, eff. 12-16-97; 91-357, eff. 7-29-99.)
24		(220 ILCS 5/8-101.1 new)
25		Sec. 8-101.1. Duties of public utilities; labor force.

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1		(a) As used in this Section:
2		"Labor force" means the employees hired directly by the
3		utility and all employees of any and all suppliers and
4		subcontractors of the utility tasked with the construction,
5		maintenance and repair of such utility's infrastructure.
6		"Public utility" means a public utility, as defined in
7		Section 3-105 of this Act, serving more than 100,000 customers
8		as of January 1, 2025.
9		"Substantial change in labor force" means either (1) a
10		greater than 5% reduction in the total labor force or (2) more
11		than a 5% decrease in the ratio of labor force spending
12		compared to capital spending.
13		(b) A public utility shall ensure that it has the
14		necessary labor force in order to furnish, provide, and
15		maintain such service instrumentalities, equipment, and
16		facilities to promote the safety, health, comfort, and
17		convenience of its patrons, employees, and the public and to
18		be in all respects adequate, efficient, just, and reasonable.
19		(c) Unless the Commission specifically orders and except
20		as otherwise provided in this Section, no substantial change
21		shall be made by any public utility in its labor force unless
22		the public utility provides notice to the Commission at least
23		45 days before the implementation of the change. A public
24		utility shall include a report with its notice that provides
25		the following:
26		(1) a detailed analysis and explanation of how and why

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1		a change in a specific law, regulation, or market factor
2		requires the public utility to make the substantial change
3		in its labor force; and
4		(2) whether the substantial change in the public
5		utility's labor force, at a minimum:
6		(i) is in the public interest;
7		(ii) will not endanger the quality and
8		availability of public utility services;
9		(iii) will not have a negative impact on the
10		safety or reliability of public utility services; and
11		(iv) is designed to minimize the financial
12		hardship on the members of its labor force impacted by
13		the substantial change.
14		(220 ILCS 5/8-103B)
15		Sec. 8-103B. Energy efficiency and demand-response
16		measures.
17		(a) It is the policy of the State that electric utilities
18		are required to use cost-effective energy efficiency and
19		demand-response measures to reduce delivery load. Requiring
20		investment in cost-effective energy efficiency and
21		demand-response measures will reduce direct and indirect costs
22		to consumers by decreasing environmental impacts and by
23		avoiding or delaying the need for new generation,
24		transmission, and distribution infrastructure. It serves the
25		public interest to allow electric utilities to recover costs

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1		for reasonably and prudently incurred expenditures for energy
2		efficiency and demand-response measures. As used in this
3		Section, "cost-effective" means that the measures satisfy the
4		total resource cost test. The low-income measures described in
5		subsection (c) of this Section shall not be required to meet
6		the total resource cost test. For purposes of this Section,
7		the terms "energy-efficiency", "demand-response", "electric
8		utility", and "total resource cost test" have the meanings set
9		forth in the Illinois Power Agency Act. "Black, indigenous,
10		and people of color" and "BIPOC" means people who are members
11		of the groups described in subparagraphs (a) through (e) of
12		paragraph (A) of subsection (1) of Section 2 of the Business
13		Enterprise for Minorities, Women, and Persons with
14		Disabilities Act.
15		(a-5) This Section applies to electric utilities serving
16		more than 500,000 retail customers in the State for those
17		multi-year plans commencing after December 31, 2017.
18		(b) For purposes of this Section, through calendar year
19		2026, electric utilities subject to this Section that serve
20		more than 3,000,000 retail customers in the State shall be
21		deemed to have achieved a cumulative persisting annual savings
22		of 6.6% from energy efficiency measures and programs
23		implemented during the period beginning January 1, 2012 and
24		ending December 31, 2017, which percent is based on the deemed
25		average weather normalized sales of electric power and energy
26		during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs.

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1		For the purposes of this subsection (b) and subsection (b-5),
2		the 88,000,000 MWhs of deemed electric power and energy sales
3		shall be reduced by the number of MWhs equal to the sum of the
4		annual consumption of customers that have opted out of
5		subsections (a) through (j) of this Section under paragraph
6		(1) of subsection (l) of this Section, as averaged across the
7		calendar years 2014, 2015, and 2016. After 2017, the deemed
8		value of cumulative persisting annual savings from energy
9		efficiency measures and programs implemented during the period
10		beginning January 1, 2012 and ending December 31, 2017, shall
11		be reduced each year, as follows, and the applicable value
12		shall be applied to and count toward the utility's achievement
13		of the cumulative persisting annual savings goals set forth in
14		subsection (b-5):
15		(1) 5.8% deemed cumulative persisting annual savings
16		for the year ending December 31, 2018;
17		(2) 5.2% deemed cumulative persisting annual savings
18		for the year ending December 31, 2019;
19		(3) 4.5% deemed cumulative persisting annual savings
20		for the year ending December 31, 2020;
21		(4) 4.0% deemed cumulative persisting annual savings
22		for the year ending December 31, 2021;
23		(5) 3.5% deemed cumulative persisting annual savings
24		for the year ending December 31, 2022;
25		(6) 3.1% deemed cumulative persisting annual savings
26		for the year ending December 31, 2023;

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1		(7) 2.8% deemed cumulative persisting annual savings
2		for the year ending December 31, 2024;
3		(8) 2.5% deemed cumulative persisting annual savings
4		for the year ending December 31, 2025; and
5		(9) 2.3% deemed cumulative persisting annual savings
6		for the year ending December 31, 2026. ;
7		(10) 2.1% deemed cumulative persisting annual savings
8		for the year ending December 31, 2027;
9		(11) 1.8% deemed cumulative persisting annual savings
10		for the year ending December 31, 2028;
11		(12) 1.7% deemed cumulative persisting annual savings
12		for the year ending December 31, 2029;
13		(13) 1.5% deemed cumulative persisting annual savings
14		for the year ending December 31, 2030;
15		(14) 1.3% deemed cumulative persisting annual savings
16		for the year ending December 31, 2031;
17		(15) 1.1% deemed cumulative persisting annual savings
18		for the year ending December 31, 2032;
19		(16) 0.9% deemed cumulative persisting annual savings
20		for the year ending December 31, 2033;
21		(17) 0.7% deemed cumulative persisting annual savings
22		for the year ending December 31, 2034;
23		(18) 0.5% deemed cumulative persisting annual savings
24		for the year ending December 31, 2035;
25		(19) 0.4% deemed cumulative persisting annual savings
26		for the year ending December 31, 2036;

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

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1		2016, through the implementation of energy efficiency measures
2		during the applicable year and in prior years, but no earlier
3		than January 1, 2012:
4		(1) 7.8% cumulative persisting annual savings for the
5		year ending December 31, 2018;
6		(2) 9.1% cumulative persisting annual savings for the
7		year ending December 31, 2019;
8		(3) 10.4% cumulative persisting annual savings for the
9		year ending December 31, 2020;
10		(4) 11.8% cumulative persisting annual savings for the
11		year ending December 31, 2021;
12		(5) 13.1% cumulative persisting annual savings for the
13		year ending December 31, 2022;
14		(6) 14.4% cumulative persisting annual savings for the
15		year ending December 31, 2023;
16		(7) 15.7% cumulative persisting annual savings for the
17		year ending December 31, 2024;
18		(8) 17% cumulative persisting annual savings for the
19		year ending December 31, 2025; and
20		(9) 17.9% cumulative persisting annual savings for the
21		year ending December 31, 2026. ;
22		(10) 18.8% cumulative persisting annual savings for
23		the year ending December 31, 2027;
24		(11) 19.7% cumulative persisting annual savings for
25		the year ending December 31, 2028;
26		(12) 20.6% cumulative persisting annual savings for

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1		the year ending December 31, 2029; and
2		(13) 21.5% cumulative persisting annual savings for
3		the year ending December 31, 2030.
4		No later than December 31, 2021, the Illinois Commerce
5		Commission shall establish additional cumulative persisting
6		annual savings goals for the years 2031 through 2035. No later
7		than December 31, 2024, the Illinois Commerce Commission shall
8		establish additional cumulative persisting annual savings
9		goals for the years 2036 through 2040. The Commission shall
10		also establish additional cumulative persisting annual savings
11		goals every 5 years thereafter to ensure that utilities always
12		have goals that extend at least 11 years into the future. The
13		cumulative persisting annual savings goals beyond the year
14		2030 shall increase by 0.9 percentage points per year, absent
15		a Commission decision to initiate a proceeding to consider
16		establishing goals that increase by more or less than that
17		amount. Such a proceeding must be conducted in accordance with
18		the procedures described in subsection (f) of this Section. If
19		such a proceeding is initiated, the cumulative persisting
20		annual savings goals established by the Commission through
21		that proceeding shall reflect the Commission's best estimate
22		of the maximum amount of additional savings that are forecast
23		to be cost-effectively achievable unless such best estimates
24		would result in goals that represent less than 0.5 percentage
25		point annual increases in total cumulative persisting annual
26		savings. The Commission may only establish goals that

SB0025 Enrolled - 522 - LRB104 07069 BAB 17106 b
1		represent less than 0.5 percentage point annual increases in
2		cumulative persisting annual savings if it can demonstrate,
3		based on clear and convincing evidence and through independent
4		analysis, that 0.5 percentage point increases are not
5		cost-effectively achievable. The Commission shall inform its
6		decision based on an energy efficiency potential study that
7		conforms to the requirements of this Section.
8		(b-10) For purposes of this Section, through calendar year
9		2026, electric utilities subject to this Section that serve
10		less than 3,000,000 retail customers but more than 500,000
11		retail customers in the State shall be deemed to have achieved
12		a cumulative persisting annual savings of 6.6% from energy
13		efficiency measures and programs implemented during the period
14		beginning January 1, 2012 and ending December 31, 2017, which
15		is based on the deemed average weather normalized sales of
16		electric power and energy during calendar years 2014, 2015,
17		and 2016 of 36,900,000 MWhs. For the purposes of this
18		subsection (b-10) and subsection (b-15), the 36,900,000 MWhs
19		of deemed electric power and energy sales shall be reduced by
20		the number of MWhs equal to the sum of the annual consumption
21		of customers that have opted out of subsections (a) through
22		(j) of this Section under paragraph (1) of subsection (l) of
23		this Section, as averaged across the calendar years 2014,
24		2015, and 2016. After 2017, the deemed value of cumulative
25		persisting annual savings from energy efficiency measures and
26		programs implemented during the period beginning January 1,

SB0025 Enrolled - 523 - LRB104 07069 BAB 17106 b
1		2012 and ending December 31, 2017, shall be reduced each year,
2		as follows, and the applicable value shall be applied to and
3		count toward the utility's achievement of the cumulative
4		persisting annual savings goals set forth in subsection
5		(b-15):
6		(1) 5.8% deemed cumulative persisting annual savings
7		for the year ending December 31, 2018;
8		(2) 5.2% deemed cumulative persisting annual savings
9		for the year ending December 31, 2019;
10		(3) 4.5% deemed cumulative persisting annual savings
11		for the year ending December 31, 2020;
12		(4) 4.0% deemed cumulative persisting annual savings
13		for the year ending December 31, 2021;
14		(5) 3.5% deemed cumulative persisting annual savings
15		for the year ending December 31, 2022;
16		(6) 3.1% deemed cumulative persisting annual savings
17		for the year ending December 31, 2023;
18		(7) 2.8% deemed cumulative persisting annual savings
19		for the year ending December 31, 2024;
20		(8) 2.5% deemed cumulative persisting annual savings
21		for the year ending December 31, 2025; and
22		(9) 2.3% deemed cumulative persisting annual savings
23		for the year ending December 31, 2026. ;
24		(10) 2.1% deemed cumulative persisting annual savings
25		for the year ending December 31, 2027;
26		(11) 1.8% deemed cumulative persisting annual savings

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1		for the year ending December 31, 2028;
2		(12) 1.7% deemed cumulative persisting annual savings
3		for the year ending December 31, 2029;
4		(13) 1.5% deemed cumulative persisting annual savings
5		for the year ending December 31, 2030;
6		(14) 1.3% deemed cumulative persisting annual savings
7		for the year ending December 31, 2031;
8		(15) 1.1% deemed cumulative persisting annual savings
9		for the year ending December 31, 2032;
10		(16) 0.9% deemed cumulative persisting annual savings
11		for the year ending December 31, 2033;
12		(17) 0.7% deemed cumulative persisting annual savings
13		for the year ending December 31, 2034;
14		(18) 0.5% deemed cumulative persisting annual savings
15		for the year ending December 31, 2035;
16		(19) 0.4% deemed cumulative persisting annual savings
17		for the year ending December 31, 2036;
18		(20) 0.3% deemed cumulative persisting annual savings
19		for the year ending December 31, 2037;
20		(21) 0.2% deemed cumulative persisting annual savings
21		for the year ending December 31, 2038;
22		(22) 0.1% deemed cumulative persisting annual savings
23		for the year ending December 31, 2039; and
24		(23) 0.0% deemed cumulative persisting annual savings
25		for the year ending December 31, 2040 and all subsequent
26		years.

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1		(b-15) Beginning in 2018 and through calendar year 2026,
2		electric utilities subject to this Section that serve less
3		than 3,000,000 retail customers but more than 500,000 retail
4		customers in the State shall achieve the following cumulative
5		persisting annual savings goals, as modified by subsection
6		(b-20) and subsection (f) of this Section and as compared to
7		the deemed baseline as reduced by the number of MWhs equal to
8		the sum of the annual consumption of customers that have opted
9		out of subsections (a) through (j) of this Section under
10		paragraph (1) of subsection (l) of this Section as averaged
11		across the calendar years 2014, 2015, and 2016, through the
12		implementation of energy efficiency measures during the
13		applicable year and in prior years, but no earlier than
14		January 1, 2012:
15		(1) 7.4% cumulative persisting annual savings for the
16		year ending December 31, 2018;
17		(2) 8.2% cumulative persisting annual savings for the
18		year ending December 31, 2019;
19		(3) 9.0% cumulative persisting annual savings for the
20		year ending December 31, 2020;
21		(4) 9.8% cumulative persisting annual savings for the
22		year ending December 31, 2021;
23		(5) 10.6% cumulative persisting annual savings for the
24		year ending December 31, 2022;
25		(6) 11.4% cumulative persisting annual savings for the
26		year ending December 31, 2023;

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1		(7) 12.2% cumulative persisting annual savings for the
2		year ending December 31, 2024;
3		(8) 13% cumulative persisting annual savings for the
4		year ending December 31, 2025; and
5		(9) 13.6% cumulative persisting annual savings for the
6		year ending December 31, 2026. ;
7		(10) 14.2% cumulative persisting annual savings for
8		the year ending December 31, 2027;
9		(11) 14.8% cumulative persisting annual savings for
10		the year ending December 31, 2028;
11		(12) 15.4% cumulative persisting annual savings for
12		the year ending December 31, 2029; and
13		(13) 16% cumulative persisting annual savings for the
14		year ending December 31, 2030.
15		No later than December 31, 2021, the Illinois Commerce
16		Commission shall establish additional cumulative persisting
17		annual savings goals for the years 2031 through 2035. No later
18		than December 31, 2024, the Illinois Commerce Commission shall
19		establish additional cumulative persisting annual savings
20		goals for the years 2036 through 2040. The Commission shall
21		also establish additional cumulative persisting annual savings
22		goals every 5 years thereafter to ensure that utilities always
23		have goals that extend at least 11 years into the future. The
24		cumulative persisting annual savings goals beyond the year
25		2030 shall increase by 0.6 percentage points per year, absent
26		a Commission decision to initiate a proceeding to consider

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

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

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1		coincident peak demand reduction achieved by the utility
2		through its energy efficiency programs in 2023. If the
3		season in which coincident peak demands are experienced,
4		the hours of the day that peak demands are experienced,
5		and the methods by which peak demand impacts from
6		efficiency measures are estimated are different in the
7		future than when 2023 peak demand impacts were originally
8		estimated, the 2023 peak demand impacts shall be
9		recomputed using such updated peak definitions and
10		estimation methods for the purpose of establishing future
11		coincident peak demand savings goals. To the extent that a
12		utility counts either improvements to the efficiency of
13		the use of gas and other fuels or the electrification of
14		gas and other fuels toward its energy savings goal, as
15		permitted under paragraphs (b-25) and (b-27) of this
16		Section, it must estimate the actual impacts on coincident
17		peak demand from such measures and count them, whether
18		positive or negative, toward its coincident peak demand
19		savings goal. Only coincident peak demand savings from
20		efficiency measures shall count toward this goal. To the
21		extent that some efficiency measures enable demand
22		response, only the peak demand savings from the energy
23		efficiency upgrade shall count toward the goal. Nothing in
24		this Section shall limit the ability of peak demand
25		savings from such enabled demand-response initiatives to
26		count for other, non-energy efficiency performance

SB0025 Enrolled - 530 - LRB104 07069 BAB 17106 b
1		standard performance metrics established for the utility.
2		(3) Each utility's incremental annual energy savings,
3		and coincident peak demand savings if a utility serves
4		less than 3,000,000 retail customers but more than 500,000
5		retail customers in the State, must be achieved with an
6		average savings life of at least 12 years. In no event can
7		more than one-fifth of the incremental annual savings or
8		the coincident peak demand savings counted toward a
9		utility's annual savings goal in any given year be derived
10		from efficiency measures with average savings lives of
11		less than 5 years. Average savings lives may be shorter
12		than the average operational lives of measures installed
13		if the measures do not produce savings in every year in
14		which the measures operate or if the savings that measures
15		produce decline during the measures' operational lives.
16		For the purposes of this Section, "incremental annual
17		energy savings" means the total electric energy savings
18		from all measures installed in a calendar year that will
19		be realized within 12 months of each measure's
20		installation; "moderate-income" means income between 80%
21		of area median income and 300% of the federal poverty
22		limit; "incremental annual coincident peak demand savings"
23		means the total coincident peak reduction from all energy
24		efficiency measures installed in a calendar year that will
25		be realized within 12 months of each measure's
26		installation; "average savings life" means the lifetime

SB0025 Enrolled - 531 - LRB104 07069 BAB 17106 b
1		savings that would be realized as a result of a utility's
2		efficiency programs divided by the incremental annual
3		savings such programs produce.
4		(b-20) Each electric utility subject to this Section may
5		include cost-effective voltage optimization measures in its
6		plans submitted under subsections (f) and (g) of this Section,
7		and the costs incurred by a utility to implement the measures
8		under a Commission-approved plan shall be recovered under the
9		provisions of Article IX or Section 16-108.5 of this Act. For
10		purposes of this Section, the measure life of voltage
11		optimization measures shall be 15 years. The measure life
12		period is independent of the depreciation rate of the voltage
13		optimization assets deployed. Utilities may claim savings from
14		voltage optimization on circuits for more than 15 years if
15		they can demonstrate that they have made additional
16		investments necessary to enable voltage optimization savings
17		to continue beyond 15 years. Such demonstrations must be
18		subject to the review of independent evaluation.
19		Within 270 days after June 1, 2017 (the effective date of
20		Public Act 99-906), an electric utility that serves less than
21		3,000,000 retail customers but more than 500,000 retail
22		customers in the State shall file a plan with the Commission
23		that identifies the cost-effective voltage optimization
24		investment the electric utility plans to undertake through
25		December 31, 2024. The Commission, after notice and hearing,
26		shall approve or approve with modification the plan within 120

SB0025 Enrolled - 532 - LRB104 07069 BAB 17106 b
1		days after the plan's filing and, in the order approving or
2		approving with modification the plan, the Commission shall
3		adjust the applicable cumulative persisting annual savings
4		goals set forth in subsection (b-15) to reflect any amount of
5		cost-effective energy savings approved by the Commission that
6		is greater than or less than the following cumulative
7		persisting annual savings values attributable to voltage
8		optimization for the applicable year:
9		(1) 0.0% of cumulative persisting annual savings for
10		the year ending December 31, 2018;
11		(2) 0.17% of cumulative persisting annual savings for
12		the year ending December 31, 2019;
13		(3) 0.17% of cumulative persisting annual savings for
14		the year ending December 31, 2020;
15		(4) 0.33% of cumulative persisting annual savings for
16		the year ending December 31, 2021;
17		(5) 0.5% of cumulative persisting annual savings for
18		the year ending December 31, 2022;
19		(6) 0.67% of cumulative persisting annual savings for
20		the year ending December 31, 2023;
21		(7) 0.83% of cumulative persisting annual savings for
22		the year ending December 31, 2024; and
23		(8) 1.0% of cumulative persisting annual savings for
24		the year ending December 31, 2025 and all subsequent
25		years.
26		(b-25) In the event an electric utility jointly offers an

SB0025 Enrolled - 533 - LRB104 07069 BAB 17106 b
1		energy efficiency measure or program with a gas utility under
2		plans approved under this Section and Section 8-104 of this
3		Act, the electric utility may continue offering the program,
4		including the gas energy efficiency measures, in the event the
5		gas utility discontinues funding the program. In that event,
6		the energy savings value associated with such other fuels
7		shall be converted to electric energy savings on an equivalent
8		Btu basis for the premises. However, the electric utility
9		shall prioritize programs for low-income residential customers
10		to the extent practicable. An electric utility may recover the
11		costs of offering the gas energy efficiency measures under
12		this subsection (b-25).
13		For those energy efficiency measures or programs that save
14		both electricity and other fuels but are not jointly offered
15		with a gas utility under plans approved under this Section and
16		Section 8-104 or not offered with an affiliated gas utility
17		under paragraph (6) of subsection (f) of Section 8-104 of this
18		Act, the electric utility may count savings of fuels other
19		than electricity toward the achievement of its annual savings
20		goal, and the energy savings value associated with such other
21		fuels shall be converted to electric energy savings on an
22		equivalent Btu basis at the premises.
23		For an electric utility that serves more than 3,000,000
24		retail customers in the State, on and after January 1, 2027,
25		the electric utility may only count savings of other fuels
26		under this subsection (b-25) toward the achievement of its

SB0025 Enrolled - 534 - LRB104 07069 BAB 17106 b
1		annual electric energy savings goal when such other fuel
2		savings are from weatherization measures that reduce heat loss
3		through the building envelope, insulating mechanical systems,
4		or the heating distribution system, including, but not limited
5		to, air sealing and building shell measures. This limitation
6		on counting other fuel savings from efficiency measures toward
7		a utility's energy savings goal shall not affect the utility's
8		ability to claim savings from electrification measures
9		installed pursuant to the requirements in subsection (b-27).
10		In no event shall more than 10% of each year's applicable
11		annual total savings requirement, as defined in paragraph
12		(7.5) of subsection (g) of this Section be met through savings
13		of fuels other than electricity. For an electric utility that
14		serves more than 3,000,000 retail customers in the State, in
15		no event shall more than 30% of each year's incremental annual
16		energy savings requirement, as defined in subsection (b-16) of
17		this Section, be met through savings of fuels other than
18		electricity. For an electric utility that serves less than
19		3,000,000 retail customers but more than 500,000 retail
20		customers in the State, in no event shall more than 20% of each
21		year's incremental annual energy savings requirement, as
22		defined in subsection (b-16) of this Section, be met through
23		savings of fuels other than electricity.
24		(b-27) Beginning in 2022, an electric utility may offer
25		and promote measures that electrify space heating, water
26		heating, cooling, drying, cooking, industrial processes, and

SB0025 Enrolled - 535 - LRB104 07069 BAB 17106 b
1		other building and industrial end uses that would otherwise be
2		served by combustion of fossil fuel at the premises, provided
3		that the electrification measures reduce total energy
4		consumption at the premises. The electric utility may count
5		the reduction in energy consumption at the premises toward
6		achievement of its annual savings goals. The reduction in
7		energy consumption at the premises shall be calculated as the
8		difference between: (A) the reduction in Btu consumption of
9		fossil fuels as a result of electrification, converted to
10		kilowatt-hour equivalents by dividing by 3,412 Btus per
11		kilowatt hour; and (B) the increase in kilowatt hours of
12		electricity consumption resulting from the displacement of
13		fossil fuel consumption as a result of electrification. An
14		electric utility may recover the costs of offering and
15		promoting electrification measures under this subsection
16		(b-27).
17		At least 33% of all costs of offering and promoting
18		electrification measures under this subsection (b-27) must be
19		for supporting installation of electrification measures
20		through programs exclusively targeted to low-income
21		households. The percentage requirement may be reduced if the
22		utility can demonstrate that it is not possible to achieve the
23		level of low-income electrification spending, while supporting
24		programs for non-low-income residential and business
25		electrification, because of limitations regarding the number
26		of low-income households in its service territory that would

SB0025 Enrolled - 536 - LRB104 07069 BAB 17106 b
1		be able to meet program eligibility requirements set forth in
2		the multi-year energy efficiency plan. If the 33% low-income
3		electrification spending requirement is reduced, the utility
4		must prioritize support of low-income electrification in
5		housing that meets program eligibility requirements over
6		electrification spending on non-low-income residential or
7		business customers.
8		The ratio of spending on electrification measures targeted
9		to low-income, multifamily buildings to spending on
10		electrification measures targeted to low-income, single-family
11		buildings shall be designed to achieve levels of
12		electrification savings from each building type that are
13		approximately proportional to the magnitude of cost-effective
14		electrification savings potential in each building type.
15		In no event shall electrification savings counted toward
16		each year's applicable annual total savings requirement, as
17		defined in paragraph (7.5) of subsection (g) of this Section,
18		or counted toward each year's incremental annual savings, as
19		defined in paragraph (b-16) of this Section, be greater than:
20		(1) 5% per year for each year from 2022 through 2025;
21		(2) 20% 10% per year for each year from 2026 and all
22		subsequent years through 2029; and
23		(3) (blank). 15% per year for 2030 and all subsequent
24		years.
25		In addition, a minimum of 25% of all electrification savings
26		counted toward a utility's applicable annual total savings

SB0025 Enrolled - 537 - LRB104 07069 BAB 17106 b
1		requirement must be from electrification of end uses in
2		low-income housing. The limitations on electrification savings
3		that may be counted toward a utility's annual savings goals
4		are separate from and in addition to the subsection (b-25)
5		limitations governing the counting of the other fuel savings
6		resulting from efficiency measures and programs.
7		As part of the annual informational filing to the
8		Commission that is required under paragraph (9) of subsection
9		(g) of this Section, each utility shall identify the specific
10		electrification measures offered under this subsection (b-27);
11		the quantity of each electrification measure that was
12		installed by its customers; the average total cost, average
13		utility cost, average reduction in fossil fuel consumption,
14		and average increase in electricity consumption associated
15		with each electrification measure; the portion of
16		installations of each electrification measure that were in
17		low-income single-family housing, low-income multifamily
18		housing, non-low-income single-family housing, non-low-income
19		multifamily housing, commercial buildings, and industrial
20		facilities; and the quantity of savings associated with each
21		measure category in each customer category that are being
22		counted toward the utility's applicable annual total savings
23		requirement or counted toward each year's incremental annual
24		savings, as defined in paragraph (b-16) of this Section. Prior
25		to installing or promoting an electrification measures
26		measure, the utility shall provide customers a customer with

SB0025 Enrolled - 538 - LRB104 07069 BAB 17106 b
1		estimates an estimate of the impact of the new measures
2		measure on the customer's average monthly electric bill and
3		total annual energy expenses.
4		(c) Electric utilities shall be responsible for overseeing
5		the design, development, and filing of energy efficiency plans
6		with the Commission and may, as part of that implementation,
7		outsource various aspects of program development and
8		implementation. A minimum of 10%, for electric utilities that
9		serve more than 3,000,000 retail customers in the State, and a
10		minimum of 7%, for electric utilities that serve less than
11		3,000,000 retail customers but more than 500,000 retail
12		customers in the State, of the utility's entire portfolio
13		funding level for a given year shall be used to procure
14		cost-effective energy efficiency measures from units of local
15		government, municipal corporations, school districts, public
16		housing, public institutions of higher education, and
17		community college districts, provided that a minimum
18		percentage of available funds shall be used to procure energy
19		efficiency from public housing, which percentage shall be
20		equal to public housing's share of public building energy
21		consumption.
22		The utilities shall also implement energy efficiency
23		measures targeted at low-income households, which, for
24		purposes of this Section, shall be defined as households at or
25		below 80% of area median income, and expenditures to implement
26		the measures shall be no less than 25% of total energy

SB0025 Enrolled - 539 - LRB104 07069 BAB 17106 b
1		efficiency program spending approved by the Commission
2		pursuant to review of plans filed under subsection (f) of this
3		Section $40,000,000 per year for electric utilities that serve
4		more than 3,000,000 retail customers in the State and no less
5		than $13,000,000 per year for electric utilities that serve
6		less than 3,000,000 retail customers but more than 500,000
7		retail customers in the State. The ratio of spending on
8		efficiency programs targeted at low-income multifamily
9		buildings to spending on efficiency programs targeted at
10		low-income single-family buildings shall be designed to
11		achieve levels of savings from each building type that are
12		approximately proportional to the magnitude of cost-effective
13		lifetime savings potential in each building type. Investment
14		in low-income whole-building weatherization programs shall
15		constitute a minimum of 80% of a utility's total budget
16		specifically dedicated to serving low-income customers.
17		The utilities shall work to bundle low-income energy
18		efficiency offerings with other programs that serve low-income
19		households to maximize the benefits going to these households.
20		The utilities shall market and implement low-income energy
21		efficiency programs in coordination with low-income assistance
22		programs, the Illinois Solar for All Program, and
23		weatherization whenever practicable. The program implementer
24		shall walk the customer through the enrollment process for any
25		programs for which the customer is eligible. The utilities
26		shall also pilot targeting customers with high arrearages,

SB0025 Enrolled - 540 - LRB104 07069 BAB 17106 b
1		high energy intensity (ratio of energy usage divided by home
2		or unit square footage), or energy assistance programs with
3		energy efficiency offerings, and then track reduction in
4		arrearages as a result of the targeting. This targeting and
5		bundling of low-income energy programs shall be offered to
6		both low-income single-family and multifamily customers
7		(owners and residents).
8		The utilities shall invest in health and safety measures
9		appropriate and necessary for comprehensively weatherizing a
10		home or multifamily building, and shall implement a health and
11		safety fund of at least 15% of the total income-qualified
12		weatherization budget that shall be used for the purpose of
13		making grants for technical assistance, construction,
14		reconstruction, improvement, or repair of buildings to
15		facilitate their participation in the energy efficiency
16		programs targeted at low-income single-family and multifamily
17		households. These funds may also be used for the purpose of
18		making grants for technical assistance, construction,
19		reconstruction, improvement, or repair of the following
20		buildings to facilitate their participation in the energy
21		efficiency programs created by this Section: (1) buildings
22		that are owned or operated by registered 501(c)(3) public
23		charities; and (2) day care centers, day care homes, or group
24		day care homes, as defined under 89 Ill. Adm. Code Part 406,
25		407, or 408, respectively.
26		Each electric utility shall assess opportunities to

SB0025 Enrolled - 541 - LRB104 07069 BAB 17106 b
1		implement cost-effective energy efficiency measures and
2		programs through a public housing authority or authorities
3		located in its service territory. If such opportunities are
4		identified, the utility shall propose such measures and
5		programs to address the opportunities. Expenditures to address
6		such opportunities shall be credited toward the minimum
7		procurement and expenditure requirements set forth in this
8		subsection (c).
9		Implementation of energy efficiency measures and programs
10		targeted at low-income households should be contracted, when
11		it is practicable, to independent third parties that have
12		demonstrated capabilities to serve such households, with a
13		preference for not-for-profit entities and government agencies
14		that have existing relationships with or experience serving
15		low-income communities in the State.
16		Each electric utility shall develop and implement
17		reporting procedures that address and assist in determining
18		the amount of energy savings that can be applied to the
19		low-income procurement and expenditure requirements set forth
20		in this subsection (c). Each electric utility shall also track
21		the types and quantities or volumes of insulation and air
22		sealing materials, and their associated energy saving
23		benefits, installed in energy efficiency programs targeted at
24		low-income single-family and multifamily households.
25		The electric utilities shall participate in a low-income
26		energy efficiency accountability committee ("the committee"),

SB0025 Enrolled - 542 - LRB104 07069 BAB 17106 b
1		which will directly inform the design, implementation, and
2		evaluation of the low-income and public-housing energy
3		efficiency programs. The committee shall be comprised of the
4		electric utilities subject to the requirements of this
5		Section, the gas utilities subject to the requirements of
6		Section 8-104 of this Act, the utilities' low-income energy
7		efficiency implementation contractors, nonprofit
8		organizations, community action agencies, advocacy groups,
9		State and local governmental agencies, public-housing
10		organizations, and representatives of community-based
11		organizations, especially those living in or working with
12		environmental justice communities and BIPOC communities. The
13		committee shall be composed of 2 geographically differentiated
14		subcommittees: one for stakeholders in northern Illinois and
15		one for stakeholders in central and southern Illinois. The
16		subcommittees shall meet together at least twice per year.
17		There shall be one statewide leadership committee led by
18		and composed of community-based organizations that are
19		representative of BIPOC and environmental justice communities
20		and that includes equitable representation from BIPOC
21		communities. The leadership committee shall be composed of an
22		equal number of representatives from the 2 subcommittees. The
23		subcommittees shall address specific programs and issues, with
24		the leadership committee convening targeted workgroups as
25		needed. The leadership committee may elect to work with an
26		independent facilitator to solicit and organize feedback,

SB0025 Enrolled - 543 - LRB104 07069 BAB 17106 b
1		recommendations and meeting participation from a wide variety
2		of community-based stakeholders. If a facilitator is used,
3		they shall be fair and responsive to the needs of all
4		stakeholders involved in the committee. For a utility that
5		serves more than 3,000,000 retail customers in the State, if a
6		facilitator is used, they shall be retained by Commission
7		staff.
8		All committee meetings must be accessible, with rotating
9		locations if meetings are held in-person, virtual
10		participation options, and materials and agendas circulated in
11		advance.
12		There shall also be opportunities for direct input by
13		committee members outside of committee meetings, such as via
14		individual meetings, surveys, emails and calls, to ensure
15		robust participation by stakeholders with limited capacity and
16		ability to attend committee meetings. Committee meetings shall
17		emphasize opportunities to bundle and coordinate delivery of
18		low-income energy efficiency with other programs that serve
19		low-income communities, such as the Illinois Solar for All
20		Program and bill payment assistance programs. Meetings shall
21		include educational opportunities for stakeholders to learn
22		more about these additional offerings, and the committee shall
23		assist in figuring out the best methods for coordinated
24		delivery and implementation of offerings when serving
25		low-income communities. The committee shall directly and
26		equitably influence and inform utility low-income and

SB0025 Enrolled - 544 - LRB104 07069 BAB 17106 b
1		public-housing energy efficiency programs and priorities.
2		Participating utilities shall implement recommendations from
3		the committee whenever possible.
4		Participating utilities shall track and report how input
5		from the committee has led to new approaches and changes in
6		their energy efficiency portfolios. This reporting shall occur
7		at committee meetings and in quarterly energy efficiency
8		reports to the Stakeholder Advisory Group and Illinois
9		Commerce Commission, and other relevant reporting mechanisms.
10		Participating utilities shall also report on relevant equity
11		data and metrics requested by the committee, such as energy
12		burden data, geographic, racial, and other relevant
13		demographic data on where programs are being delivered and
14		what populations programs are serving.
15		The Illinois Commerce Commission shall oversee and have
16		relevant staff participate in the committee. The committee
17		shall have a budget of 0.25% of each utility's entire
18		efficiency portfolio funding for a given year. The budget
19		shall be overseen by the Commission. The budget shall be used
20		to provide grants for community-based organizations serving on
21		the leadership committee, stipends for community-based
22		organizations participating in the committee, grants for
23		community-based organizations to do energy efficiency outreach
24		and education, and relevant meeting needs as determined by the
25		leadership committee. The education and outreach shall
26		include, but is not limited to, basic energy efficiency

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1		education, information about low-income energy efficiency
2		programs, and information on the committee's purpose,
3		structure, and activities.
4		(d) Notwithstanding any other provision of law to the
5		contrary, a utility providing approved energy efficiency
6		measures and, if applicable, demand-response measures in the
7		State shall be permitted to recover all reasonable and
8		prudently incurred costs of those measures from all retail
9		customers, except as provided in subsection (l) of this
10		Section, as follows, provided that nothing in this subsection
11		(d) permits the double recovery of such costs from customers:
12		(1) The utility may recover its costs through an
13		automatic adjustment clause tariff filed with and approved
14		by the Commission. The tariff shall be established outside
15		the context of a general rate case. Each year the
16		Commission shall initiate a review to reconcile any
17		amounts collected with the actual costs and to determine
18		the required adjustment to the annual tariff factor to
19		match annual expenditures. To enable the financing of the
20		incremental capital expenditures, including regulatory
21		assets, for electric utilities that serve less than
22		3,000,000 retail customers but more than 500,000 retail
23		customers in the State, the utility's actual year-end
24		capital structure that includes a common equity ratio,
25		excluding goodwill, of up to and including 50% of the
26		total capital structure shall be deemed reasonable and

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1		used to set rates.
2		(2) A utility may recover its costs through an energy
3		efficiency formula rate approved by the Commission under a
4		filing under subsections (f) and (g) of this Section,
5		which shall specify the cost components that form the
6		basis of the rate charged to customers with sufficient
7		specificity to operate in a standardized manner and be
8		updated annually with transparent information that
9		reflects the utility's actual costs to be recovered during
10		the applicable rate year, which is the period beginning
11		with the first billing day of January and extending
12		through the last billing day of the following December.
13		The energy efficiency formula rate shall be implemented
14		through a tariff filed with the Commission under
15		subsections (f) and (g) of this Section that is consistent
16		with the provisions of this paragraph (2) and that shall
17		be applicable to all delivery services customers. The
18		Commission shall conduct an investigation of the tariff in
19		a manner consistent with the provisions of this paragraph
20		(2), subsections (f) and (g) of this Section, and the
21		provisions of Article IX of this Act to the extent they do
22		not conflict with this paragraph (2). The energy
23		efficiency formula rate approved by the Commission shall
24		remain in effect at the discretion of the utility and
25		shall do the following:
26		(A) Provide for the recovery of the utility's

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1		actual costs incurred under this Section that are
2		prudently incurred and reasonable in amount consistent
3		with Commission practice and law. The sole fact that a
4		cost differs from that incurred in a prior calendar
5		year or that an investment is different from that made
6		in a prior calendar year shall not imply the
7		imprudence or unreasonableness of that cost or
8		investment.
9		(B) Reflect the utility's actual year-end capital
10		structure for the applicable calendar year, excluding
11		goodwill, subject to a determination of prudence and
12		reasonableness consistent with Commission practice and
13		law. To enable the financing of the incremental
14		capital expenditures, including regulatory assets, for
15		electric utilities that serve less than 3,000,000
16		retail customers but more than 500,000 retail
17		customers in the State, a participating electric
18		utility's actual year-end capital structure that
19		includes a common equity ratio, excluding goodwill, of
20		up to and including 50% of the total capital structure
21		shall be deemed reasonable and used to set rates.
22		(C) Include a cost of equity that shall be equal to
23		the baseline cost of equity approved by the Commission
24		for the utility's electric distribution rates
25		effective during the applicable year, whether those
26		rates are set pursuant to Section 9-201, subparagraph

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1		(B) of paragraph (3) of subsection (d) of Section
2		16-108.18, or any successor electric distribution
3		ratemaking paradigm. , which shall be calculated as the
4		sum of the following:
5		(i) the average for the applicable calendar
6		year of the monthly average yields of 30-year U.S.
7		Treasury bonds published by the Board of Governors
8		of the Federal Reserve System in its weekly H.15
9		Statistical Release or successor publication; and
10		(ii) 580 basis points.
11		At such time as the Board of Governors of the
12		Federal Reserve System ceases to include the monthly
13		average yields of 30-year U.S. Treasury bonds in its
14		weekly H.15 Statistical Release or successor
15		publication, the monthly average yields of the U.S.
16		Treasury bonds then having the longest duration
17		published by the Board of Governors in its weekly H.15
18		Statistical Release or successor publication shall
19		instead be used for purposes of this paragraph (2).
20		(D) Permit and set forth protocols, subject to a
21		determination of prudence and reasonableness
22		consistent with Commission practice and law, for the
23		following:
24		(i) recovery of incentive compensation expense
25		that is based on the achievement of operational
26		metrics, including metrics related to budget

SB0025 Enrolled - 549 - LRB104 07069 BAB 17106 b
1		controls, outage duration and frequency, safety,
2		customer service, efficiency and productivity, and
3		environmental compliance; however, this protocol
4		shall not apply if such expense related to costs
5		incurred under this Section is recovered under
6		Article IX or Section 16-108.5 of this Act;
7		incentive compensation expense that is based on
8		net income or an affiliate's earnings per share
9		shall not be recoverable under the energy
10		efficiency formula rate;
11		(ii) recovery of pension and other
12		post-employment benefits expense, provided that
13		such costs are supported by an actuarial study;
14		however, this protocol shall not apply if such
15		expense related to costs incurred under this
16		Section is recovered under Article IX or Section
17		16-108.5 of this Act;
18		(iii) recovery of existing regulatory assets
19		over the periods previously authorized by the
20		Commission;
21		(iv) as described in subsection (e),
22		amortization of costs incurred under this Section;
23		and
24		(v) projected, weather normalized billing
25		determinants for the applicable rate year.
26		(E) Provide for an annual reconciliation, as

SB0025 Enrolled - 550 - LRB104 07069 BAB 17106 b
1		described in paragraph (3) of this subsection (d),
2		less any deferred taxes related to the reconciliation,
3		with interest at an annual rate of return equal to the
4		utility's weighted average cost of capital, including
5		a revenue conversion factor calculated to recover or
6		refund all additional income taxes that may be payable
7		or receivable as a result of that return, of the energy
8		efficiency revenue requirement reflected in rates for
9		each calendar year, beginning with the calendar year
10		in which the utility files its energy efficiency
11		formula rate tariff under this paragraph (2), with
12		what the revenue requirement would have been had the
13		actual cost information for the applicable calendar
14		year been available at the filing date.
15		The utility shall file, together with its tariff, the
16		projected costs to be incurred by the utility during the
17		rate year under the utility's multi-year plan approved
18		under subsections (f) and (g) of this Section, including,
19		but not limited to, the projected capital investment costs
20		and projected regulatory asset balances with
21		correspondingly updated depreciation and amortization
22		reserves and expense, that shall populate the energy
23		efficiency formula rate and set the initial rates under
24		the formula.
25		The Commission shall review the proposed tariff in
26		conjunction with its review of a proposed multi-year plan,

SB0025 Enrolled - 551 - LRB104 07069 BAB 17106 b
1		as specified in paragraph (5) of subsection (g) of this
2		Section. The review shall be based on the same evidentiary
3		standards, including, but not limited to, those concerning
4		the prudence and reasonableness of the costs incurred by
5		the utility, the Commission applies in a hearing to review
6		a filing for a general increase in rates under Article IX
7		of this Act. The initial rates shall take effect beginning
8		with the January monthly billing period following the
9		Commission's approval.
10		The tariff's rate design and cost allocation across
11		customer classes shall be consistent with the utility's
12		automatic adjustment clause tariff in effect on June 1,
13		2017 (the effective date of Public Act 99-906); however,
14		the Commission may revise the tariff's rate design and
15		cost allocation in subsequent proceedings under paragraph
16		(3) of this subsection (d).
17		If the energy efficiency formula rate is terminated,
18		the then current rates shall remain in effect until such
19		time as the energy efficiency costs are incorporated into
20		new rates that are set under this subsection (d) or
21		Article IX of this Act, subject to retroactive rate
22		adjustment, with interest, to reconcile rates charged with
23		actual costs.
24		(3) The provisions of this paragraph (3) shall only
25		apply to an electric utility that has elected to file an
26		energy efficiency formula rate under paragraph (2) of this

SB0025 Enrolled - 552 - LRB104 07069 BAB 17106 b
1		subsection (d). Subsequent to the Commission's issuance of
2		an order approving the utility's energy efficiency formula
3		rate structure and protocols, and initial rates under
4		paragraph (2) of this subsection (d), the utility shall
5		file, on or before June 1 of each year, with the Chief
6		Clerk of the Commission its updated cost inputs to the
7		energy efficiency formula rate for the applicable rate
8		year and the corresponding new charges, as well as the
9		information described in paragraph (9) of subsection (g)
10		of this Section. Each such filing shall conform to the
11		following requirements and include the following
12		information:
13		(A) The inputs to the energy efficiency formula
14		rate for the applicable rate year shall be based on the
15		projected costs to be incurred by the utility during
16		the rate year under the utility's multi-year plan
17		approved under subsections (f) and (g) of this
18		Section, including, but not limited to, projected
19		capital investment costs and projected regulatory
20		asset balances with correspondingly updated
21		depreciation and amortization reserves and expense.
22		The filing shall also include a reconciliation of the
23		energy efficiency revenue requirement that was in
24		effect for the prior rate year (as set by the cost
25		inputs for the prior rate year) with the actual
26		revenue requirement for the prior rate year

SB0025 Enrolled - 553 - LRB104 07069 BAB 17106 b
1		(determined using a year-end rate base) that uses
2		amounts reflected in the applicable FERC Form 1 that
3		reports the actual costs for the prior rate year. Any
4		over-collection or under-collection indicated by such
5		reconciliation shall be reflected as a credit against,
6		or recovered as an additional charge to, respectively,
7		with interest calculated at a rate equal to the
8		utility's weighted average cost of capital approved by
9		the Commission for the prior rate year, the charges
10		for the applicable rate year. Such over-collection or
11		under-collection shall be adjusted to remove any
12		deferred taxes related to the reconciliation, for
13		purposes of calculating interest at an annual rate of
14		return equal to the utility's weighted average cost of
15		capital approved by the Commission for the prior rate
16		year, including a revenue conversion factor calculated
17		to recover or refund all additional income taxes that
18		may be payable or receivable as a result of that
19		return. Each reconciliation shall be certified by the
20		participating utility in the same manner that FERC
21		Form 1 is certified. The filing shall also include the
22		charge or credit, if any, resulting from the
23		calculation required by subparagraph (E) of paragraph
24		(2) of this subsection (d).
25		Notwithstanding any other provision of law to the
26		contrary, the intent of the reconciliation is to

SB0025 Enrolled - 554 - LRB104 07069 BAB 17106 b
1		ultimately reconcile both the revenue requirement
2		reflected in rates for each calendar year, beginning
3		with the calendar year in which the utility files its
4		energy efficiency formula rate tariff under paragraph
5		(2) of this subsection (d), with what the revenue
6		requirement determined using a year-end rate base for
7		the applicable calendar year would have been had the
8		actual cost information for the applicable calendar
9		year been available at the filing date.
10		For purposes of this Section, "FERC Form 1" means
11		the Annual Report of Major Electric Utilities,
12		Licensees and Others that electric utilities are
13		required to file with the Federal Energy Regulatory
14		Commission under the Federal Power Act, Sections 3,
15		4(a), 304 and 209, modified as necessary to be
16		consistent with 83 Ill. Adm. Code Part 415 as of May 1,
17		2011. Nothing in this Section is intended to allow
18		costs that are not otherwise recoverable to be
19		recoverable by virtue of inclusion in FERC Form 1.
20		(B) The new charges shall take effect beginning on
21		the first billing day of the following January billing
22		period and remain in effect through the last billing
23		day of the next December billing period regardless of
24		whether the Commission enters upon a hearing under
25		this paragraph (3).
26		(C) The filing shall include relevant and

SB0025 Enrolled - 555 - LRB104 07069 BAB 17106 b
1		necessary data and documentation for the applicable
2		rate year. Normalization adjustments shall not be
3		required.
4		Within 45 days after the utility files its annual
5		update of cost inputs to the energy efficiency formula
6		rate, the Commission shall with reasonable notice,
7		initiate a proceeding concerning whether the projected
8		costs to be incurred by the utility and recovered during
9		the applicable rate year, and that are reflected in the
10		inputs to the energy efficiency formula rate, are
11		consistent with the utility's approved multi-year plan
12		under subsections (f) and (g) of this Section and whether
13		the costs incurred by the utility during the prior rate
14		year were prudent and reasonable. The Commission shall
15		also have the authority to investigate the information and
16		data described in paragraph (9) of subsection (g) of this
17		Section, including the proposed adjustment to the
18		utility's return on equity component of its weighted
19		average cost of capital. During the course of the
20		proceeding, each objection shall be stated with
21		particularity and evidence provided in support thereof,
22		after which the utility shall have the opportunity to
23		rebut the evidence. Discovery shall be allowed consistent
24		with the Commission's Rules of Practice, which Rules of
25		Practice shall be enforced by the Commission or the
26		assigned administrative law judge. The Commission shall

SB0025 Enrolled - 556 - LRB104 07069 BAB 17106 b
1		apply the same evidentiary standards, including, but not
2		limited to, those concerning the prudence and
3		reasonableness of the costs incurred by the utility,
4		during the proceeding as it would apply in a proceeding to
5		review a filing for a general increase in rates under
6		Article IX of this Act. The Commission shall not, however,
7		have the authority in a proceeding under this paragraph
8		(3) to consider or order any changes to the structure or
9		protocols of the energy efficiency formula rate approved
10		under paragraph (2) of this subsection (d). In a
11		proceeding under this paragraph (3), the Commission shall
12		enter its order no later than the earlier of 195 days after
13		the utility's filing of its annual update of cost inputs
14		to the energy efficiency formula rate or December 15. The
15		utility's proposed return on equity calculation, as
16		described in paragraphs (7) through (9) of subsection (g)
17		of this Section, shall be deemed the final, approved
18		calculation on December 15 of the year in which it is filed
19		unless the Commission enters an order on or before
20		December 15, after notice and hearing, that modifies such
21		calculation consistent with this Section. The Commission's
22		determinations of the prudence and reasonableness of the
23		costs incurred, and determination of such return on equity
24		calculation, for the applicable calendar year shall be
25		final upon entry of the Commission's order and shall not
26		be subject to reopening, reexamination, or collateral

SB0025 Enrolled - 557 - LRB104 07069 BAB 17106 b
1		attack in any other Commission proceeding, case, docket,
2		order, rule, or regulation; however, nothing in this
3		paragraph (3) shall prohibit a party from petitioning the
4		Commission to rehear or appeal to the courts the order
5		under the provisions of this Act.
6		(e) Beginning on June 1, 2017 (the effective date of
7		Public Act 99-906), a utility subject to the requirements of
8		this Section may elect to defer, as a regulatory asset, up to
9		the full amount of its expenditures incurred under this
10		Section for each annual period, including, but not limited to,
11		any expenditures incurred above the funding level set by
12		subsection (f) of this Section for a given year. The total
13		expenditures deferred as a regulatory asset in a given year
14		shall be amortized and recovered over a period that is equal to
15		the weighted average of the energy efficiency measure lives
16		implemented for that year that are reflected in the regulatory
17		asset. The unamortized balance shall be recognized as of
18		December 31 for a given year. The utility shall also earn a
19		return on the total of the unamortized balances of all of the
20		energy efficiency regulatory assets, less any deferred taxes
21		related to those unamortized balances, at an annual rate equal
22		to the utility's weighted average cost of capital that
23		includes, based on a year-end capital structure, the utility's
24		actual cost of debt for the applicable calendar year and a cost
25		of equity, which shall be determined as set forth in
26		subparagraph (C) of paragraph (2) of subsection of this

SB0025 Enrolled - 558 - LRB104 07069 BAB 17106 b
1		Section calculated as the sum of the (i) the average for the
2		applicable calendar year of the monthly average yields of
3		30-year U.S. Treasury bonds published by the Board of
4		Governors of the Federal Reserve System in its weekly H.15
5		Statistical Release or successor publication; and (ii) 580
6		basis points, including a revenue conversion factor calculated
7		to recover or refund all additional income taxes that may be
8		payable or receivable as a result of that return. Capital
9		investment costs shall be depreciated and recovered over their
10		useful lives consistent with generally accepted accounting
11		principles. The weighted average cost of capital shall be
12		applied to the capital investment cost balance, less any
13		accumulated depreciation and accumulated deferred income
14		taxes, as of December 31 for a given year.
15		When an electric utility creates a regulatory asset under
16		the provisions of this Section, the costs are recovered over a
17		period during which customers also receive a benefit which is
18		in the public interest. Accordingly, it is the intent of the
19		General Assembly that an electric utility that elects to
20		create a regulatory asset under the provisions of this Section
21		shall recover all of the associated costs as set forth in this
22		Section. After the Commission has approved the prudence and
23		reasonableness of the costs that comprise the regulatory
24		asset, the electric utility shall be permitted to recover all
25		such costs, and the value and recoverability through rates of
26		the associated regulatory asset shall not be limited, altered,

SB0025 Enrolled - 559 - LRB104 07069 BAB 17106 b
1		impaired, or reduced.
2		(f) Beginning in 2017, each electric utility shall file an
3		energy efficiency plan with the Commission to meet the energy
4		efficiency standards for the next applicable multi-year period
5		beginning January 1 of the year following the filing,
6		according to the schedule set forth in paragraphs (1) through
7		(3) of this subsection (f). If a utility does not file such a
8		plan on or before the applicable filing deadline for the plan,
9		it shall face a penalty of $100,000 per day until the plan is
10		filed.
11		(1) No later than 30 days after June 1, 2017 (the
12		effective date of Public Act 99-906), each electric
13		utility shall file a 4-year energy efficiency plan
14		commencing on January 1, 2018 that is designed to achieve
15		the cumulative persisting annual savings goals specified
16		in paragraphs (1) through (4) of subsection (b-5) of this
17		Section or in paragraphs (1) through (4) of subsection
18		(b-15) of this Section, as applicable, through
19		implementation of energy efficiency measures; however, the
20		goals may be reduced if the utility's expenditures are
21		limited pursuant to subsection (m) of this Section or, for
22		a utility that serves less than 3,000,000 retail
23		customers, if each of the following conditions are met:
24		(A) the plan's analysis and forecasts of the utility's
25		ability to acquire energy savings demonstrate that
26		achievement of such goals is not cost effective; and (B)

SB0025 Enrolled - 560 - LRB104 07069 BAB 17106 b
1		the amount of energy savings achieved by the utility as
2		determined by the independent evaluator for the most
3		recent year for which savings have been evaluated
4		preceding the plan filing was less than the average annual
5		amount of savings required to achieve the goals for the
6		applicable 4-year plan period. Except as provided in
7		subsection (m) of this Section, annual increases in
8		cumulative persisting annual savings goals during the
9		applicable 4-year plan period shall not be reduced to
10		amounts that are less than the maximum amount of
11		cumulative persisting annual savings that is forecast to
12		be cost-effectively achievable during the 4-year plan
13		period. The Commission shall review any proposed goal
14		reduction as part of its review and approval of the
15		utility's proposed plan.
16		(2) No later than March 1, 2021, each electric utility
17		shall file a 4-year energy efficiency plan commencing on
18		January 1, 2022 that is designed to achieve the cumulative
19		persisting annual savings goals specified in paragraphs
20		(5) through (8) of subsection (b-5) of this Section or in
21		paragraphs (5) through (8) of subsection (b-15) of this
22		Section, as applicable, through implementation of energy
23		efficiency measures; however, the goals may be reduced if
24		either (1) clear and convincing evidence demonstrates,
25		through independent analysis, that the expenditure limits
26		in subsection (m) of this Section preclude full

SB0025 Enrolled - 561 - LRB104 07069 BAB 17106 b
1		achievement of the goals or (2) each of the following
2		conditions are met: (A) the plan's analysis and forecasts
3		of the utility's ability to acquire energy savings
4		demonstrate by clear and convincing evidence and through
5		independent analysis that achievement of such goals is not
6		cost effective; and (B) the amount of energy savings
7		achieved by the utility as determined by the independent
8		evaluator for the most recent year for which savings have
9		been evaluated preceding the plan filing was less than the
10		average annual amount of savings required to achieve the
11		goals for the applicable 4-year plan period. If there is
12		not clear and convincing evidence that achieving the
13		savings goals specified in paragraph (b-5) or (b-15) of
14		this Section is possible both cost-effectively and within
15		the expenditure limits in subsection (m), such savings
16		goals shall not be reduced. 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		(2.5) Provisions of the multi-year plans for calendar

SB0025 Enrolled - 562 - LRB104 07069 BAB 17106 b
1		years 2026 through 2029 that relate to calendar year 2026
2		and that were filed by the electric utilities on February
3		28, 2025 shall remain in effect through calendar year
4		2026. Provisions of the plans for calendar years 2027
5		through 2029 shall be modified and resubmitted to the
6		Commission by the electric utilities pursuant to paragraph
7		(3) of this subsection (f).
8		(3) No later than the effective date of this
9		amendatory Act of the 104th General Assembly March 1,
10		2025, each electric utility shall file a 3-year 4-year
11		energy efficiency plan commencing on January 1, 2027 2026
12		that is designed to achieve, through implementation of
13		energy efficiency measures, lifetime energy equal to the
14		product of the incremental annual savings goals defined by
15		paragraph (1) of subsection (b-16) and the minimum average
16		savings life defined by paragraph (3) of subsection
17		(b-16). The 3-year energy efficiency plan of a utility
18		that serves less than 3,000,000 retail customers but more
19		than 500,000 retail customers in the State must also be
20		designed to achieve lifetime peak demand savings equal to
21		the product of the incremental annual savings goals
22		defined by paragraph (2) of subsection (b-16) and the
23		minimum average savings life defined by paragraph (3) of
24		subsection (b-16) through implementation of energy
25		efficiency measures. The savings goals may be reduced if:
26		(i) clear and convincing evidence and independent analysis

SB0025 Enrolled - 563 - LRB104 07069 BAB 17106 b
1		demonstrates that the expenditure limits in subsection (m)
2		of this Section preclude full achievement of the goals,
3		(ii) each of the following conditions are met: (A) the
4		plan's analysis and forecasts of the utility's ability to
5		acquire energy savings demonstrate by clear and convincing
6		evidence and through independent analysis that achievement
7		of such goals is not cost-effective; and (B) the amount of
8		energy savings achieved by the utility, as determined by
9		the independent evaluator, for the most recent year for
10		which savings have been evaluated preceding the plan
11		filing was less than the average annual amount of savings
12		required to achieve the goals for the applicable
13		multi-year plan period, or (iii) changes in federal law,
14		programs, or tariffs have a significant and demonstrable
15		impact on the cost of delivering measures and programs. If
16		there is not clear and convincing evidence that achieving
17		the savings goals specified in subsection (b-16) is not
18		possible both cost-effectively and within the expenditure
19		limits in subsection (m), such savings goals shall not be
20		reduced. Except as provided in subsection (m), annual
21		savings goals during the applicable multi-year plan period
22		shall not be reduced to amounts that are less than the
23		maximum amount of annual savings that is forecasted to be
24		cost-effectively achievable during the applicable
25		multi-year plan period. The Commission shall review any
26		proposed goal reduction as part of its review and approval

SB0025 Enrolled - 564 - LRB104 07069 BAB 17106 b
1		of the utility's proposed plan. the cumulative persisting
2		annual savings goals specified in paragraphs (9) through
3		(12) of subsection (b-5) of this Section or in paragraphs
4		(9) through (12) of subsection (b-15) of this Section, as
5		applicable, through implementation of energy efficiency
6		measures; however, the goals may be reduced if either (1)
7		clear and convincing evidence demonstrates, through
8		independent analysis, that the expenditure limits in
9		subsection (m) of this Section preclude full achievement
10		of the goals or (2) each of the following conditions are
11		met: (A) the plan's analysis and forecasts of the
12		utility's ability to acquire energy savings demonstrate by
13		clear and convincing evidence and through independent
14		analysis that achievement of such goals is not cost
15		effective; and (B) the amount of energy savings achieved
16		by the utility as determined by the independent evaluator
17		for the most recent year for which savings have been
18		evaluated preceding the plan filing was less than the
19		average annual amount of savings required to achieve the
20		goals for the applicable 4-year plan period. If there is
21		not clear and convincing evidence that achieving the
22		savings goals specified in paragraphs (b-5) or (b-15) of
23		this Section is possible both cost-effectively and within
24		the expenditure limits in subsection (m), such savings
25		goals shall not be reduced. Except as provided in
26		subsection (m) of this Section, annual increases in

SB0025 Enrolled - 565 - LRB104 07069 BAB 17106 b
1		cumulative persisting annual savings goals during the
2		applicable 4-year plan period shall not be reduced to
3		amounts that are less than the maximum amount of
4		cumulative persisting annual savings that is forecast to
5		be cost-effectively achievable during the 4-year plan
6		period. The Commission shall review any proposed goal
7		reduction as part of its review and approval of the
8		utility's proposed plan.
9		(4) No later than March 1, 2029, and every 4 years
10		thereafter, each electric utility shall file a 4-year
11		energy efficiency plan commencing on January 1, 2030, and
12		every 4 years thereafter, respectively, that is designed
13		to achieve the cumulative persisting annual savings goals
14		established by the Illinois Commerce Commission pursuant
15		to direction of subsections (b-5) and (b-15) of this
16		Section, as applicable, through implementation of energy
17		efficiency measures, lifetime energy equal to the product
18		of the incremental annual savings goals defined by
19		paragraph (1) of subsection (b-16) and the minimum average
20		savings life described in paragraph (C) of subsection
21		(b-16) of this Section. The multi-year energy efficiency
22		plan of a utility that serves less than 3,000,000 retail
23		customers but more than 500,000 retail customers in the
24		State must also be designed to achieve lifetime peak
25		demand savings equal to the product of the incremental
26		annual savings goals defined by paragraph (2) of

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

SB0025 Enrolled - 567 - LRB104 07069 BAB 17106 b
1		Section, annual increases in cumulative persisting annual
2		savings goals during the applicable multi-year 4-year plan
3		period shall not be reduced to amounts that are less than
4		the maximum amount of cumulative persisting annual savings
5		that is forecast to be cost-effectively achievable during
6		the applicable multi-year 4-year plan period. The
7		Commission shall review any proposed goal reduction as
8		part of its review and approval of the utility's proposed
9		plan.
10		Each utility's plan shall set forth the utility's
11		proposals to meet the energy efficiency standards identified
12		in subsection (b-5), or (b-15), or (b-16), as applicable and
13		as such standards may have been modified under this subsection
14		(f), taking into account the unique circumstances of the
15		utility's service territory. For those plans commencing on
16		January 1, 2018, the Commission shall seek public comment on
17		the utility's plan and shall issue an order approving or
18		disapproving each plan no later than 105 days after June 1,
19		2017 (the effective date of Public Act 99-906). For those
20		plans commencing after December 31, 2021, the Commission shall
21		seek public comment on the utility's plan and shall issue an
22		order approving or disapproving each plan within 6 months
23		after its submission. If the Commission disapproves a plan,
24		the Commission shall, within 30 days, describe in detail the
25		reasons for the disapproval and describe a path by which the
26		utility may file a revised draft of the plan to address the

SB0025 Enrolled - 568 - LRB104 07069 BAB 17106 b
1		Commission's concerns satisfactorily. If the utility does not
2		refile with the Commission within 60 days, the utility shall
3		be subject to penalties at a rate of $100,000 per day until the
4		plan is filed. This process shall continue, and penalties
5		shall accrue, until the utility has successfully filed a
6		portfolio of energy efficiency and demand-response measures.
7		Penalties shall be deposited into the Energy Efficiency Trust
8		Fund.
9		(g) In submitting proposed plans and funding levels under
10		subsection (f) of this Section to meet the savings goals
11		identified in subsection (b-5), or (b-15), or (b-16) of this
12		Section, as applicable, the utility shall:
13		(1) Demonstrate that its proposed energy efficiency
14		measures will achieve the applicable requirements that are
15		identified in subsection (b-5), or (b-15), or (b-16) of
16		this Section, as modified by subsection (f) of this
17		Section.
18		(2) (Blank).
19		(2.5) Demonstrate consideration of program options for
20		(A) advancing new building codes, appliance standards, and
21		municipal regulations governing existing and new building
22		efficiency improvements and (B) supporting efforts to
23		improve compliance with new building codes, appliance
24		standards and municipal regulations, as potentially
25		cost-effective means of acquiring energy savings to count
26		toward savings goals.

SB0025 Enrolled - 569 - LRB104 07069 BAB 17106 b
1		(3) Demonstrate that its overall portfolio of
2		measures, not including low-income programs described in
3		subsection (c) of this Section, is cost-effective using
4		the total resource cost test or complies with paragraphs
5		(1) through (3) of subsection (f) of this Section and
6		represents a diverse cross-section of opportunities for
7		customers of all rate classes, other than those customers
8		described in subsection (l) of this Section, to
9		participate in the programs. Individual measures need not
10		be cost effective.
11		(3.5) Demonstrate that the utility's plan integrates
12		the delivery of energy efficiency programs with natural
13		gas efficiency programs, programs promoting distributed
14		solar, programs promoting demand response and other
15		efforts to address bill payment issues, including, but not
16		limited to, LIHEAP and the Percentage of Income Payment
17		Plan, to the extent such integration is practical and has
18		the potential to enhance customer engagement, minimize
19		market confusion, or reduce administrative costs.
20		(4) If the utility chooses, present Present a
21		third-party energy efficiency implementation program
22		subject to the following requirements:
23		(A) (blank); beginning with the year commencing
24		January 1, 2019, electric utilities that serve more
25		than 3,000,000 retail customers in the State shall
26		fund third-party energy efficiency programs in an

SB0025 Enrolled - 570 - LRB104 07069 BAB 17106 b
1		amount that is no less than $25,000,000 per year, and
2		electric utilities that serve less than 3,000,000
3		retail customers but more than 500,000 retail
4		customers in the State shall fund third-party energy
5		efficiency programs in an amount that is no less than
6		$8,350,000 per year;
7		(B) during 2018, the utility shall conduct a
8		solicitation process for purposes of requesting
9		proposals from third-party vendors for those
10		third-party energy efficiency programs to be offered
11		during one or more of the years commencing January 1,
12		2019, January 1, 2020, and January 1, 2021; for those
13		multi-year plans commencing on January 1, 2022 and
14		January 1, 2026, the utility shall conduct a
15		solicitation process during 2021 and 2025,
16		respectively, for purposes of requesting proposals
17		from third-party vendors for those third-party energy
18		efficiency programs to be offered during one or more
19		years of the respective multi-year plan period; for
20		each solicitation process, the utility shall identify
21		the sector, technology, or geographical area for which
22		it is seeking requests for proposals; the solicitation
23		process must be either for programs that fill gaps in
24		the utility's program portfolio and for programs that
25		target low-income customers, business sectors,
26		building types, geographies, or other specific parts

SB0025 Enrolled - 571 - LRB104 07069 BAB 17106 b
1		of its customer base with initiatives that would be
2		more effective at reaching these customer segments
3		than the utilities' programs filed in its energy
4		efficiency plans;
5		(C) the utility shall propose the bidder
6		qualifications, performance measurement process, and
7		contract structure, which must include a performance
8		payment mechanism and general terms and conditions;
9		the proposed qualifications, process, and structure
10		shall be subject to Commission approval; and
11		(D) the utility shall retain an independent third
12		party to score the proposals received through the
13		solicitation process described in this paragraph (4),
14		rank them according to their cost per lifetime
15		kilowatt-hours saved, and assemble the portfolio of
16		third-party programs.
17		The electric utility shall recover all costs
18		associated with Commission-approved, third-party
19		administered programs regardless of the success of those
20		programs.
21		(4.5) Implement cost-effective demand-response
22		measures to reduce peak demand by 0.1% over the prior year
23		for eligible retail customers, as defined in Section
24		16-111.5 of this Act, and for customers that elect hourly
25		service from the utility pursuant to Section 16-107 of
26		this Act, provided those customers have not been declared

SB0025 Enrolled - 572 - LRB104 07069 BAB 17106 b
1		competitive. This requirement continues until December 31,
2		2026.
3		(5) Include a proposed or revised cost-recovery tariff
4		mechanism, as provided for under subsection (d) of this
5		Section, to fund the proposed energy efficiency and
6		demand-response measures and to ensure the recovery of the
7		prudently and reasonably incurred costs of
8		Commission-approved programs.
9		(6) Provide for an annual independent evaluation of
10		the performance of the cost-effectiveness of the utility's
11		portfolio of measures, as well as a full review of the
12		multi-year plan results of the broader net program impacts
13		and, to the extent practical, for adjustment of the
14		measures on a going-forward basis as a result of the
15		evaluations. The resources dedicated to evaluation shall
16		not exceed 3% of portfolio resources in any given year.
17		(7) For electric utilities that serve more than
18		3,000,000 retail customers in the State:
19		(A) Through December 31, 2026 2025, provide for an
20		adjustment to the return on equity component of the
21		utility's weighted average cost of capital calculated
22		under subsection (d) of this Section:
23		(i) If the independent evaluator determines
24		that the utility achieved a cumulative persisting
25		annual savings that is less than the applicable
26		annual incremental goal, then the return on equity

SB0025 Enrolled - 573 - LRB104 07069 BAB 17106 b
1		component shall be reduced by a maximum of 200
2		basis points in the event that the utility
3		achieved no more than 75% of such goal. If the
4		utility achieved more than 75% of the applicable
5		annual incremental goal but less than 100% of such
6		goal, then the return on equity component shall be
7		reduced by 8 basis points for each percent by
8		which the utility failed to achieve the goal.
9		(ii) If the independent evaluator determines
10		that the utility achieved a cumulative persisting
11		annual savings that is more than the applicable
12		annual incremental goal, then the return on equity
13		component shall be increased by a maximum of 200
14		basis points in the event that the utility
15		achieved at least 125% of such goal. If the
16		utility achieved more than 100% of the applicable
17		annual incremental goal but less than 125% of such
18		goal, then the return on equity component shall be
19		increased by 8 basis points for each percent by
20		which the utility achieved above the goal. If the
21		applicable annual incremental goal was reduced
22		under paragraph (1) or (2) of subsection (f) of
23		this Section, then the following adjustments shall
24		be made to the calculations described in this item
25		(ii):
26		(aa) the calculation for determining

SB0025 Enrolled - 574 - LRB104 07069 BAB 17106 b
1		achievement that is at least 125% of the
2		applicable annual incremental goal shall use
3		the unreduced applicable annual incremental
4		goal to set the value; and
5		(bb) the calculation for determining
6		achievement that is less than 125% but more
7		than 100% of the applicable annual incremental
8		goal shall use the reduced applicable annual
9		incremental goal to set the value for 100%
10		achievement of the goal and shall use the
11		unreduced goal to set the value for 125%
12		achievement. The 8 basis point value shall
13		also be modified, as necessary, so that the
14		200 basis points are evenly apportioned among
15		each percentage point value between 100% and
16		125% achievement.
17		(B) (Blank). For the period January 1, 2026
18		through December 31, 2029 and in all subsequent 4-year
19		periods, provide for an adjustment to the return on
20		equity component of the utility's weighted average
21		cost of capital calculated under subsection (d) of
22		this Section:
23		(i) If the independent evaluator determines
24		that the utility achieved a cumulative persisting
25		annual savings that is less than the applicable
26		annual incremental goal, then the return on equity

SB0025 Enrolled - 575 - LRB104 07069 BAB 17106 b
1		component shall be reduced by a maximum of 200
2		basis points in the event that the utility
3		achieved no more than 66% of such goal. If the
4		utility achieved more than 66% of the applicable
5		annual incremental goal but less than 100% of such
6		goal, then the return on equity component shall be
7		reduced by 6 basis points for each percent by
8		which the utility failed to achieve the goal.
9		(ii) If the independent evaluator determines
10		that the utility achieved a cumulative persisting
11		annual savings that is more than the applicable
12		annual incremental goal, then the return on equity
13		component shall be increased by a maximum of 200
14		basis points in the event that the utility
15		achieved at least 134% of such goal. If the
16		utility achieved more than 100% of the applicable
17		annual incremental goal but less than 134% of such
18		goal, then the return on equity component shall be
19		increased by 6 basis points for each percent by
20		which the utility achieved above the goal. If the
21		applicable annual incremental goal was reduced
22		under paragraph (3) of subsection (f) of this
23		Section, then the following adjustments shall be
24		made to the calculations described in this item
25		(ii):
26		(aa) the calculation for determining

SB0025 Enrolled - 576 - LRB104 07069 BAB 17106 b
1		achievement that is at least 134% of the
2		applicable annual incremental goal shall use
3		the unreduced applicable annual incremental
4		goal to set the value; and
5		(bb) the calculation for determining
6		achievement that is less than 134% but more
7		than 100% of the applicable annual incremental
8		goal shall use the reduced applicable annual
9		incremental goal to set the value for 100%
10		achievement of the goal and shall use the
11		unreduced goal to set the value for 134%
12		achievement. The 6 basis point value shall
13		also be modified, as necessary, so that the
14		200 basis points are evenly apportioned among
15		each percentage point value between 100% and
16		134% achievement.
17		(C) (Blank). Notwithstanding the provisions of
18		subparagraphs (A) and (B) of this paragraph (7), if
19		the applicable annual incremental goal for an electric
20		utility is ever less than 0.6% of deemed average
21		weather normalized sales of electric power and energy
22		during calendar years 2014, 2015, and 2016, an
23		adjustment to the return on equity component of the
24		utility's weighted average cost of capital calculated
25		under subsection (d) of this Section shall be made as
26		follows:

SB0025 Enrolled - 577 - LRB104 07069 BAB 17106 b
1		(i) If the independent evaluator determines
2		that the utility achieved a cumulative persisting
3		annual savings that is less than would have been
4		achieved had the applicable annual incremental
5		goal been achieved, then the return on equity
6		component shall be reduced by a maximum of 200
7		basis points if the utility achieved no more than
8		75% of its applicable annual total savings
9		requirement as defined in paragraph (7.5) of this
10		subsection. If the utility achieved more than 75%
11		of the applicable annual total savings requirement
12		but less than 100% of such goal, then the return on
13		equity component shall be reduced by 8 basis
14		points for each percent by which the utility
15		failed to achieve the goal.
16		(ii) If the independent evaluator determines
17		that the utility achieved a cumulative persisting
18		annual savings that is more than would have been
19		achieved had the applicable annual incremental
20		goal been achieved, then the return on equity
21		component shall be increased by a maximum of 200
22		basis points if the utility achieved at least 125%
23		of its applicable annual total savings
24		requirement. If the utility achieved more than
25		100% of the applicable annual total savings
26		requirement but less than 125% of such goal, then

SB0025 Enrolled - 578 - LRB104 07069 BAB 17106 b
1		the return on equity component shall be increased
2		by 8 basis points for each percent by which the
3		utility achieved above the applicable annual total
4		savings requirement. If the applicable annual
5		incremental goal was reduced under paragraph (1)
6		or (2) of subsection (f) of this Section, then the
7		following adjustments shall be made to the
8		calculations described in this item (ii):
9		(aa) the calculation for determining
10		achievement that is at least 125% of the
11		applicable annual total savings requirement
12		shall use the unreduced applicable annual
13		incremental goal to set the value; and
14		(bb) the calculation for determining
15		achievement that is less than 125% but more
16		than 100% of the applicable annual total
17		savings requirement shall use the reduced
18		applicable annual incremental goal to set the
19		value for 100% achievement of the goal and
20		shall use the unreduced goal to set the value
21		for 125% achievement. The 8 basis point value
22		shall also be modified, as necessary, so that
23		the 200 basis points are evenly apportioned
24		among each percentage point value between 100%
25		and 125% achievement.
26		(7.5) For purposes of this Section, the term

SB0025 Enrolled - 579 - LRB104 07069 BAB 17106 b
1		"applicable annual incremental goal" means the difference
2		between the cumulative persisting annual savings goal for
3		the calendar year that is the subject of the independent
4		evaluator's determination and the cumulative persisting
5		annual savings goal for the immediately preceding calendar
6		year, as such goals are defined in subsections (b-5) and
7		(b-15) of this Section and as these goals may have been
8		modified as provided for under subsection (b-20) and
9		paragraphs (1) and (2) through (3) of subsection (f) of
10		this Section. Under subsections (b), (b-5), (b-10), and
11		(b-15) of this Section, a utility must first replace
12		energy savings from measures that have expired before any
13		progress towards achievement of its applicable annual
14		incremental goal may be counted. Savings may expire
15		because measures installed in previous years have reached
16		the end of their lives, because measures installed in
17		previous years are producing lower savings in the current
18		year than in the previous year, or for other reasons
19		identified by independent evaluators. Notwithstanding
20		anything else set forth in this Section, the difference
21		between the actual annual incremental savings achieved in
22		any given year, including the replacement of energy
23		savings that have expired, and the applicable annual
24		incremental goal shall not affect adjustments to the
25		return on equity for subsequent calendar years under this
26		subsection (g).

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1		In this Section, "applicable annual total savings
2		requirement" means the total amount of new annual savings
3		that the utility must achieve in any given year to achieve
4		the applicable annual incremental goal. This is equal to
5		the applicable annual incremental goal plus the total new
6		annual savings that are required to replace savings that
7		expired in or at the end of the previous year.
8		(8) For electric utilities that serve less than
9		3,000,000 retail customers but more than 500,000 retail
10		customers in the State:
11		(A) Through December 31, 2026 2025, the applicable
12		annual incremental goal shall be compared to the
13		annual incremental savings as determined by the
14		independent evaluator.
15		(i) The return on equity component shall be
16		reduced by 8 basis points for each percent by
17		which the utility did not achieve 84.4% of the
18		applicable annual incremental goal.
19		(ii) The return on equity component shall be
20		increased by 8 basis points for each percent by
21		which the utility exceeded 100% of the applicable
22		annual incremental goal.
23		(iii) The return on equity component shall not
24		be increased or decreased if the annual
25		incremental savings as determined by the
26		independent evaluator is greater than 84.4% of the

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

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

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1		achievement that is at least 125% or 134%, as
2		applicable, of the applicable annual incremental
3		goal or the applicable annual total savings
4		requirement, as applicable, shall use the
5		unreduced applicable annual incremental goal to
6		set the value.
7		(ii) For the period through December 31, 2025,
8		the calculation for determining achievement that
9		is less than 125% but more than 100% of the
10		applicable annual incremental goal or the
11		applicable annual total savings requirement, as
12		applicable, shall use the reduced applicable
13		annual incremental goal to set the value for 100%
14		achievement of the goal and shall use the
15		unreduced goal to set the value for 125%
16		achievement. The 8 basis point value shall also be
17		modified, as necessary, so that the 200 basis
18		points are evenly apportioned among each
19		percentage point value between 100% and 125%
20		achievement.
21		(iii) For the period of January 1, 2026
22		through December 31, 2029 and all subsequent
23		4-year periods, the calculation for determining
24		achievement that is less than 125% or 134%, as
25		applicable, but more than 100% of the applicable
26		annual incremental goal or the applicable annual

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1		total savings requirement, as applicable, shall
2		use the reduced applicable annual incremental goal
3		to set the value for 100% achievement of the goal
4		and shall use the unreduced goal to set the value
5		for 125% achievement. The 6 basis-point value or 8
6		basis-point value, as applicable, shall also be
7		modified, as necessary, so that the 200 basis
8		points are evenly apportioned among each
9		percentage point value between 100% and 125% or
10		between 100% and 134% achievement, as applicable.
11		(8.5) Beginning January 1, 2027, a utility that serves
12		greater than 500,000 retail customers in the State shall
13		have the utility's return on equity modified for
14		performance on the utility's energy savings and peak
15		demand savings goals as follows:
16		(A) The return on equity for a utility that serves
17		more than 3,000,000 retail customers in the State may
18		be adjusted up or down by a maximum of 200 basis points
19		for its performance relative to its incremental annual
20		energy savings goal. The return on equity for a
21		utility that serves less than 3,000,000 retail
22		customers but more than 500,000 retail customers in
23		the State may be adjusted up or down by a maximum of
24		100 basis points for its performance relative to its
25		incremental annual energy savings goal and a maximum
26		of 100 basis points for its performance relative to

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1		its incremental annual coincident peak demand savings
2		goal.
3		(B) A utility's performance on its savings goals
4		shall be established by comparing the actual lifetime
5		energy, and coincident peak demand savings if a
6		utility serves less than 3,000,000 retail customers
7		but more than 500,000 retail customers in the State,
8		achieved from efficiency measures installed in a given
9		year to the product of the incremental annual goals
10		established in paragraphs (1) and (2) of subsection
11		(b-16) and the minimum average savings lives
12		established in paragraph (3) of subsection (b-16), as
13		modified, if applicable, by the Commission under
14		paragraph (4) of subsection (f) of this Section. For
15		the purposes of this paragraph (8.5), "lifetime
16		savings" means the total incremental savings that
17		installed efficiency measures are projected to
18		produce, relative to what would have occurred absent
19		to the utility's efficiency programs, over the useful
20		lives of the measures. Performance on the energy
21		savings goal, and coincident peak demand savings if a
22		utility serves less than 3,000,000 retail customers
23		but more than 500,000 retail customers in the State,
24		shall be assessed separately, such that it is possible
25		to earn penalties on both, earn bonuses on both, or
26		earn a bonus for performance on one goal and a penalty

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1		on the other.
2		(C) No bonus shall be earned if a utility does not
3		achieve greater than 100% of an approved goal. The
4		maximum bonus for a goal shall be earned if the utility
5		achieves 125% of the unmodified goal. For a utility
6		that serves less than 3,000,000 retail customers but
7		more than 500,000 retail customers in the State, the
8		bonus earned for achieving more than 100% of an
9		approved goal but less than 125% of the unmodified
10		goal shall be linearly interpolated. For a utility
11		with more than 3,000,000 retail customers, the maximum
12		bonus for a goal shall be earned if the utility
13		achieves 125% of the unmodified goal. For a utility
14		with more than 3,000,000 retail customers, the bonus
15		earned for achieving more than 100% of an approved
16		goal but less than 125% of the unmodified goal shall be
17		linearly interpolated.
18		(D) For utilities with greater than 3,000,000
19		retail customers, the return on equity shall be
20		unmodified due to performance on an individual goal
21		only if the utility achieves exactly 100% of the goal.
22		For utilities with more than 500,000 but fewer than
23		3,000,000 retail customers, the return on equity shall
24		be unmodified for achieving between 85% and 100% of
25		the goal.
26		(E) Penalties may be earned for falling short of

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1		goals, with the magnitude of any penalty being a
2		function of both the size of the utility and whether
3		goals established in subsection (b-16) are modified by
4		the Commission under paragraph (4) of subsection (f)
5		of this Section, as follows:
6		(i) If the savings goals specified in
7		subsection (b-16) of this Section are unmodified,
8		a utility with more than 3,000,000 retail
9		customers shall earn the maximum penalty allocated
10		to a goal for achieving 75% or less of the goal.
11		The penalty for achieving greater than 75% but
12		less than 100% of the goal shall be linearly
13		interpolated.
14		(ii) If the savings goals specified in
15		subsection (b-16) of this Section are unmodified,
16		a utility with more than 500,000 but fewer than
17		3,000,000 retail customers shall earn the maximum
18		penalty allocated to a goal for achieving at least
19		33.3 percentage points less than the bottom end of
20		the deadband specified in subparagraph (D) of this
21		paragraph (8.5). The penalty for achieving less
22		than the bottom end of the deadband and greater
23		than 33.3 percentage points less than the bottom
24		end of the deadband shall be linearly
25		interpolated.
26		(iii) If either the energy or peak demand

SB0025 Enrolled - 588 - LRB104 07069 BAB 17106 b
1		savings goals specified in subsection (b-16) are
2		reduced under paragraph (3) or (4) of subsection
3		(f) of this Section, the maximum penalty allocated
4		to a goal shall be earned if the utility achieves
5		80% or less of the modified goal. The penalty for
6		achieving more than 80% but less than 100% of a
7		modified goal shall be linearly interpolated.
8		(9) The utility shall submit the energy savings data
9		to the independent evaluator no later than 30 days after
10		the close of the plan year. The independent evaluator
11		shall determine the cumulative persisting annual savings
12		and annual incremental savings for a given plan year, as
13		well as an estimate of job impacts and other macroeconomic
14		impacts of the efficiency programs for that year, no later
15		than 120 days after the close of the plan year. The utility
16		shall submit an informational filing to the Commission no
17		later than 160 days after the close of the plan year that
18		attaches the independent evaluator's final report
19		identifying the cumulative persisting annual savings for
20		the year and calculates, under paragraph (7) or (8) of
21		this subsection (g), as applicable, any resulting change
22		to the utility's return on equity component of the
23		weighted average cost of capital applicable to the next
24		plan year beginning with the January monthly billing
25		period and extending through the December monthly billing
26		period. However, if the utility recovers the costs

SB0025 Enrolled - 589 - LRB104 07069 BAB 17106 b
1		incurred under this Section under paragraphs (2) and (3)
2		of subsection (d) of this Section, then the utility shall
3		not be required to submit such informational filing, and
4		shall instead submit the information that would otherwise
5		be included in the informational filing as part of its
6		filing under paragraph (3) of such subsection (d) that is
7		due on or before June 1 of each year.
8		For those utilities that must submit the informational
9		filing, the Commission may, on its own motion or by
10		petition, initiate an investigation of such filing,
11		provided, however, that the utility's proposed return on
12		equity calculation shall be deemed the final, approved
13		calculation on December 15 of the year in which it is filed
14		unless the Commission enters an order on or before
15		December 15, after notice and hearing, that modifies such
16		calculation consistent with this Section.
17		The adjustments to the return on equity component
18		described in paragraphs (7) and (8) of this subsection (g)
19		shall be applied as described in such paragraphs through a
20		separate tariff mechanism, which shall be filed by the
21		utility under subsections (f) and (g) of this Section.
22		(9.5) The utility must demonstrate how it will ensure
23		that program implementation contractors and energy
24		efficiency installation vendors will promote workforce
25		equity and quality jobs. For all construction,
26		installation, or other related services procured under

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

SB0025 Enrolled - 591 - LRB104 07069 BAB 17106 b
1		working on such programs. These reports must include data
2		on vendor and employee diversity, including data on the
3		implementation of paragraphs (9.5) and (9.6) and the
4		proportion of total program dollars awarded to firms that
5		meet the criteria of subparagraphs (A) and (B) of
6		paragraph (9.5). If the utility is not meeting the
7		requirements of paragraphs (9.5) and (9.6), the utility
8		shall submit a plan to adjust their activities so that
9		they meet the requirements of paragraphs (9.5) and (9.6)
10		within the following year.
11		(h) No more than 4% of energy efficiency and
12		demand-response program revenue may be allocated for research,
13		development, or pilot deployment of new equipment or measures.
14		Electric utilities shall work with interested stakeholders to
15		formulate a plan for how these funds should be spent,
16		incorporate statewide approaches for these allocations, and
17		file a 4-year plan that demonstrates that collaboration. If a
18		utility files a request for modified annual energy savings
19		goals with the Commission, then a utility shall forgo spending
20		portfolio dollars on research and development proposals.
21		(i) When practicable, electric utilities shall incorporate
22		advanced metering infrastructure data into the planning,
23		implementation, and evaluation of energy efficiency measures
24		and programs, subject to the data privacy and confidentiality
25		protections of applicable law.
26		(j) The independent evaluator shall follow the guidelines

SB0025 Enrolled - 592 - LRB104 07069 BAB 17106 b
1		and use the savings set forth in Commission-approved energy
2		efficiency policy manuals and technical reference manuals, as
3		each may be updated from time to time. Until such time as
4		measure life values for energy efficiency measures implemented
5		for low-income households under subsection (c) of this Section
6		are incorporated into such Commission-approved manuals, the
7		low-income measures shall have the same measure life values
8		that are established for same measures implemented in
9		households that are not low-income households.
10		(k) Notwithstanding any provision of law to the contrary,
11		an electric utility subject to the requirements of this
12		Section may file a tariff cancelling an automatic adjustment
13		clause tariff in effect under this Section or Section 8-103,
14		which shall take effect no later than one business day after
15		the date such tariff is filed. Thereafter, the utility shall
16		be authorized to defer and recover its expenditures incurred
17		under this Section through a new tariff authorized under
18		subsection (d) of this Section or in the utility's next rate
19		case under Article IX or Section 16-108.5 of this Act, with
20		interest at an annual rate equal to the utility's weighted
21		average cost of capital as approved by the Commission in such
22		case. If the utility elects to file a new tariff under
23		subsection (d) of this Section, the utility may file the
24		tariff within 10 days after June 1, 2017 (the effective date of
25		Public Act 99-906), and the cost inputs to such tariff shall be
26		based on the projected costs to be incurred by the utility

SB0025 Enrolled - 593 - LRB104 07069 BAB 17106 b
1		during the calendar year in which the new tariff is filed and
2		that were not recovered under the tariff that was cancelled as
3		provided for in this subsection. Such costs shall include
4		those incurred or to be incurred by the utility under its
5		multi-year plan approved under subsections (f) and (g) of this
6		Section, including, but not limited to, projected capital
7		investment costs and projected regulatory asset balances with
8		correspondingly updated depreciation and amortization reserves
9		and expense. The Commission shall, after notice and hearing,
10		approve, or approve with modification, such tariff and cost
11		inputs no later than 75 days after the utility filed the
12		tariff, provided that such approval, or approval with
13		modification, shall be consistent with the provisions of this
14		Section to the extent they do not conflict with this
15		subsection (k). The tariff approved by the Commission shall
16		take effect no later than 5 days after the Commission enters
17		its order approving the tariff.
18		No later than 60 days after the effective date of the
19		tariff cancelling the utility's automatic adjustment clause
20		tariff, the utility shall file a reconciliation that
21		reconciles the moneys collected under its automatic adjustment
22		clause tariff with the costs incurred during the period
23		beginning June 1, 2016 and ending on the date that the electric
24		utility's automatic adjustment clause tariff was cancelled. In
25		the event the reconciliation reflects an under-collection, the
26		utility shall recover the costs as specified in this

SB0025 Enrolled - 594 - LRB104 07069 BAB 17106 b
1		subsection (k). If the reconciliation reflects an
2		over-collection, the utility shall apply the amount of such
3		over-collection as a one-time credit to retail customers'
4		bills.
5		(l) For the calendar years covered by a multi-year plan
6		commencing after December 31, 2017, subsections (a) through
7		(j) of this Section do not apply to eligible large private
8		energy customers that have chosen to opt out of multi-year
9		plans consistent with this subsection (1).
10		(1) For purposes of this subsection (l), "eligible
11		large private energy customer" means any retail customers,
12		except for federal, State, municipal, and other public
13		customers, of an electric utility that serves more than
14		3,000,000 retail customers, except for federal, State,
15		municipal and other public customers, in the State and
16		whose total highest 30 minute demand was more than 10,000
17		kilowatts, or any retail customers of an electric utility
18		that serves less than 3,000,000 retail customers but more
19		than 500,000 retail customers in the State and whose total
20		highest 15 minute demand was more than 10,000 kilowatts.
21		For purposes of this subsection (l), "retail customer" has
22		the meaning set forth in Section 16-102 of this Act.
23		However, for a business entity with multiple sites located
24		in the State, where at least one of those sites qualifies
25		as an eligible large private energy customer, then any of
26		that business entity's sites, properly identified on a

SB0025 Enrolled - 595 - LRB104 07069 BAB 17106 b
1		form for notice, shall be considered eligible large
2		private energy customers for the purposes of this
3		subsection (l). A determination of whether this subsection
4		is applicable to a customer shall be made for each
5		multi-year plan beginning after December 31, 2017. The
6		criteria for determining whether this subsection (l) is
7		applicable to a retail customer shall be based on the 12
8		consecutive billing periods prior to the start of the
9		first year of each such multi-year plan.
10		(2) Within 45 days after September 15, 2021 (the
11		effective date of Public Act 102-662), the Commission
12		shall prescribe the form for notice required for opting
13		out of energy efficiency programs. The notice must be
14		submitted to the retail electric utility 12 months before
15		the next energy efficiency planning cycle. However, within
16		120 days after the Commission's initial issuance of the
17		form for notice, eligible large private energy customers
18		may submit a form for notice to an electric utility. The
19		form for notice for opting out of energy efficiency
20		programs shall include all of the following:
21		(A) a statement indicating that the customer has
22		elected to opt out;
23		(B) the account numbers for the customer accounts
24		to which the opt out shall apply;
25		(C) the mailing address associated with the
26		customer accounts identified under subparagraph (B);

SB0025 Enrolled - 596 - LRB104 07069 BAB 17106 b
1		(D) an American Society of Heating, Refrigerating,
2		and Air-Conditioning Engineers (ASHRAE) level 2 or
3		higher audit report conducted by an independent
4		third-party expert identifying cost-effective energy
5		efficiency project opportunities that could be
6		invested in over the next 10 years. A retail customer
7		with specialized processes may utilize a self-audit
8		process in lieu of the ASHRAE audit;
9		(E) a description of the customer's plans to
10		reallocate the funds toward internal energy efficiency
11		efforts identified in the subparagraph (D) report,
12		including, but not limited to: (i) strategic energy
13		management or other programs, including descriptions
14		of targeted buildings, equipment and operations; (ii)
15		eligible energy efficiency measures; and (iii)
16		expected energy savings, itemized by technology. If
17		the subparagraph (D) audit report identifies that the
18		customer currently utilizes the best available energy
19		efficient technology, equipment, programs, and
20		operations, the customer may provide a statement that
21		more efficient technology, equipment, programs, and
22		operations are not reasonably available as a means of
23		satisfying this subparagraph (E); and
24		(F) the effective date of the opt out, which will
25		be the next January 1 following notice of the opt out.
26		(3) Upon receipt of a properly and timely noticed

SB0025 Enrolled - 597 - LRB104 07069 BAB 17106 b
1		request for opt out submitted by an eligible large private
2		energy customer, the retail electric utility shall grant
3		the request, file the request with the Commission and,
4		beginning January 1 of the following year, the opted out
5		customer shall no longer be assessed the costs of the plan
6		and shall be prohibited from participating in that 4-year
7		plan cycle to give the retail utility the certainty to
8		design program plan proposals.
9		(4) Upon a customer's election to opt out under
10		paragraphs (1) and (2) of this subsection (l) and
11		commencing on the effective date of said opt out, the
12		account properly identified in the customer's notice under
13		paragraph (2) shall not be subject to any cost recovery
14		and shall not be eligible to participate in, or directly
15		benefit from, compliance with energy efficiency cumulative
16		persisting savings requirements under subsections (a)
17		through (j).
18		(5) A utility's cumulative persisting annual savings
19		targets will exclude any opted out load.
20		(6) The request to opt out is only valid for the
21		requested plan cycle. An eligible large private energy
22		customer must also request to opt out for future energy
23		plan cycles, otherwise the customer will be included in
24		the future energy plan cycle.
25		(m) Notwithstanding the requirements of this Section, as
26		part of a proceeding to approve a multi-year plan under

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1		subsections (f) and (g) of this Section if the multi-year plan
2		has been designed to maximize savings, but does not meet the
3		cost cap limitations of this Section, the Commission shall
4		reduce the amount of energy efficiency measures implemented
5		for any single year, and whose costs are recovered under
6		subsection (d) of this Section, by an amount necessary to
7		limit the estimated average net increase due to the cost of the
8		measures to no more than
9		(1) 3.5% for each of the 4 years beginning January 1,
10		2018,
11		(2) (blank),
12		(3) 4% for each of the 4 years beginning January 1,
13		2022,
14		(3.5) 4.25% for 2026,
15		(4) 4.25% for electric utilities that serve more than
16		3,000,000 retail customers in the State, and 4.21% for
17		2027, 5.25% for 2028, and 6.06% for 2029 for electric
18		utilities with less than 3,000,000 retail customers but
19		more than 500,000 retail customers in the State, for the 3
20		4 years beginning January 1, 2027 2026, and
21		(5) the percentage specified in paragraph (4)
22		applicable to 2029 4.25% plus an increase sufficient to
23		account for the rate of inflation between January 1, 2027
24		2026 and January 1 of the first year of each subsequent
25		4-year plan cycle,
26		of the average amount paid per kilowatthour by residential

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1		eligible retail customers during calendar year 2015 for plans
2		in effect through 2026 and during calendar year 2023 for plans
3		commencing in 2027 and thereafter. An electric utility may
4		plan to spend up to 10% more in any year during an applicable
5		multi-year plan period, including any transition period
6		authorized under paragraph (2.5) of subsection (f), to
7		cost-effectively achieve additional savings so long as the
8		average over the applicable multi-year plan period, which
9		shall include any transition period, does not exceed the
10		percentages defined in items (1) through (5). To determine the
11		total amount that may be spent by an electric utility in any
12		single year, the applicable percentage of the average amount
13		paid per kilowatthour shall be multiplied by the total amount
14		of energy delivered by such electric utility in the calendar
15		year 2015 for plans in effect through 2026 and during calendar
16		year 2023 for plans commencing in 2027 and thereafter,
17		adjusted to reflect the proportion of the utility's load
18		attributable to customers that have opted out of subsections
19		(a) through (j) of this Section under subsection (l) of this
20		Section. For purposes of this subsection (m), the amount paid
21		per kilowatthour includes, without limitation, estimated
22		amounts paid for supply, transmission, distribution,
23		surcharges, and add-on taxes. For purposes of this Section,
24		"eligible retail customers" shall have the meaning set forth
25		in Section 16-111.5 of this Act. Once the Commission has
26		approved a plan under subsections (f) and (g) of this Section,

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1		no subsequent rate impact determinations shall be made.
2		(n) A utility shall take advantage of the efficiencies
3		available through existing Illinois Home Weatherization
4		Assistance Program infrastructure and services, such as
5		enrollment, marketing, quality assurance and implementation,
6		which can reduce the need for similar services at a lower cost
7		than utility-only programs, subject to capacity constraints at
8		community action agencies, for both single-family and
9		multifamily weatherization services, to the extent Illinois
10		Home Weatherization Assistance Program community action
11		agencies provide multifamily services. A utility's plan shall
12		demonstrate that in formulating annual weatherization budgets,
13		it has sought input and coordination with community action
14		agencies regarding agencies' capacity to expand and maximize
15		Illinois Home Weatherization Assistance Program delivery using
16		the ratepayer dollars collected under this Section.
17		(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23;
18		103-613, eff. 7-1-24.)
19		(220 ILCS 5/8-104)
20		Sec. 8-104. Natural gas energy efficiency programs.
21		(a) It is the policy of the State that natural gas
22		utilities and the Department of Commerce and Economic
23		Opportunity are required to use cost-effective energy
24		efficiency to reduce direct and indirect costs to consumers.
25		It serves the public interest to allow natural gas utilities

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1		to recover costs for reasonably and prudently incurred
2		expenses for cost-effective energy efficiency measures.
3		(b) For purposes of this Section, "energy efficiency"
4		means measures that reduce the amount of energy required to
5		achieve a given end use. "Energy efficiency" also includes
6		measures that reduce the total Btus of electricity and natural
7		gas needed to meet the end use or uses. "Cost-effective" means
8		that the measures satisfy the total resource cost test which,
9		for purposes of this Section, means a standard that is met if,
10		for an investment in energy efficiency, the benefit-cost ratio
11		is greater than one. The benefit-cost ratio is the ratio of the
12		net present value of the total benefits of the measures to the
13		net present value of the total costs as calculated over the
14		lifetime of the measures. The total resource cost test
15		compares the sum of avoided natural gas utility costs,
16		representing the benefits that accrue to the system and the
17		participant in the delivery of those efficiency measures, as
18		well as other quantifiable societal benefits, including
19		avoided electric utility costs, to the sum of all incremental
20		costs of end use measures (including both utility and
21		participant contributions), plus costs to administer, deliver,
22		and evaluate each demand-side measure, to quantify the net
23		savings obtained by substituting demand-side measures for
24		supply resources. In calculating avoided costs, reasonable
25		estimates shall be included for financial costs likely to be
26		imposed by future regulation of emissions of greenhouse gases.

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1		The low-income programs described in item (4) of subsection
2		(f) of this Section shall not be required to meet the total
3		resource cost test.
4		(c) Natural gas utilities shall implement cost-effective
5		energy efficiency measures to meet at least the following
6		natural gas savings requirements, which shall be based upon
7		the total amount of gas delivered to retail customers, other
8		than the customers described in subsection (m) of this
9		Section, during calendar year 2009 multiplied by the
10		applicable percentage. Natural gas utilities may comply with
11		this Section by meeting the annual incremental savings goal in
12		the applicable year or by showing that total cumulative annual
13		savings within a multi-year planning period associated with
14		measures implemented after May 31, 2011 were equal to the sum
15		of each annual incremental savings requirement from the first
16		day of the multi-year planning period through the last day of
17		the multi-year planning period:
18		(1) 0.2% by May 31, 2012;
19		(2) an additional 0.4% by May 31, 2013, increasing
20		total savings to .6%;
21		(3) an additional 0.6% by May 31, 2014, increasing
22		total savings to 1.2%;
23		(4) an additional 0.8% by May 31, 2015, increasing
24		total savings to 2.0%;
25		(5) an additional 1% by May 31, 2016, increasing total
26		savings to 3.0%;

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1		(6) an additional 1.2% by May 31, 2017, increasing
2		total savings to 4.2%;
3		(7) an additional 1.4% in the year commencing January
4		1, 2018;
5		(8) an additional 1.5% in the year commencing January
6		1, 2019; and
7		(9) an additional 1.5% in each 12-month period
8		thereafter.
9		(d) Notwithstanding the requirements of subsection (c) of
10		this Section, a natural gas utility shall limit the amount of
11		energy efficiency implemented in any multi-year reporting
12		period established by subsection (f) of Section 8-104 of this
13		Act, by an amount necessary to limit the estimated average
14		increase in the amounts paid by retail customers in connection
15		with natural gas service to no more than 2% in the applicable
16		multi-year reporting period. The energy savings requirements
17		in subsection (c) of this Section may be reduced by the
18		Commission for the subject plan, if the utility demonstrates
19		by substantial evidence that it is highly unlikely that the
20		requirements could be achieved without exceeding the
21		applicable spending limits in any multi-year reporting period.
22		No later than September 1, 2013, the Commission shall review
23		the limitation on the amount of energy efficiency measures
24		implemented pursuant to this Section and report to the General
25		Assembly, in the report required by subsection (k) of this
26		Section, its findings as to whether that limitation unduly

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1		constrains the procurement of energy efficiency measures.
2		(e) The provisions of this subsection (e) apply to those
3		multi-year plans that commence prior to January 1, 2018. The
4		utility shall utilize 75% of the available funding associated
5		with energy efficiency programs approved by the Commission,
6		and may outsource various aspects of program development and
7		implementation. The remaining 25% of available funding shall
8		be used by the Department of Commerce and Economic Opportunity
9		to implement energy efficiency measures that achieve no less
10		than 20% of the requirements of subsection (c) of this
11		Section. Such measures shall be designed in conjunction with
12		the utility and approved by the Commission. The Department may
13		outsource development and implementation of energy efficiency
14		measures. A minimum of 10% of the entire portfolio of
15		cost-effective energy efficiency measures shall be procured
16		from local government, municipal corporations, school
17		districts, public institutions of higher education, and
18		community college districts. Five percent of the entire
19		portfolio of cost-effective energy efficiency measures may be
20		granted to local government and municipal corporations for
21		market transformation initiatives. The Department shall
22		coordinate the implementation of these measures and shall
23		integrate delivery of natural gas efficiency programs with
24		electric efficiency programs delivered pursuant to Section
25		8-103 of this Act, unless the Department can show that
26		integration is not feasible.

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1		The apportionment of the dollars to cover the costs to
2		implement the Department's share of the portfolio of energy
3		efficiency measures shall be made to the Department once the
4		Department has executed rebate agreements, grants, or
5		contracts for energy efficiency measures and provided
6		supporting documentation for those rebate agreements, grants,
7		and contracts to the utility. The Department is authorized to
8		adopt any rules necessary and prescribe procedures in order to
9		ensure compliance by applicants in carrying out the purposes
10		of rebate agreements for energy efficiency measures
11		implemented by the Department made under this Section.
12		The details of the measures implemented by the Department
13		shall be submitted by the Department to the Commission in
14		connection with the utility's filing regarding the energy
15		efficiency measures that the utility implements.
16		The portfolio of measures, administered by both the
17		utilities and the Department, shall, in combination, be
18		designed to achieve the annual energy savings requirements set
19		forth in subsection (c) of this Section, as modified by
20		subsection (d) of this Section.
21		The utility and the Department shall agree upon a
22		reasonable portfolio of measures and determine the measurable
23		corresponding percentage of the savings goals associated with
24		measures implemented by the Department.
25		No utility shall be assessed a penalty under subsection
26		(f) of this Section for failure to make a timely filing if that

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1		failure is the result of a lack of agreement with the
2		Department with respect to the allocation of responsibilities
3		or related costs or target assignments. In that case, the
4		Department and the utility shall file their respective plans
5		with the Commission and the Commission shall determine an
6		appropriate division of measures and programs that meets the
7		requirements of this Section.
8		(e-5) The provisions of this subsection (e-5) shall be
9		applicable to those multi-year plans that commence after
10		December 31, 2017. Natural gas utilities shall be responsible
11		for overseeing the design, development, and filing of their
12		efficiency plans with the Commission and may outsource
13		development and implementation of energy efficiency measures.
14		A minimum of 10% of the entire portfolio of cost-effective
15		energy efficiency measures shall be procured from local
16		government, municipal corporations, school districts, public
17		institutions of higher education, and community college
18		districts; unless a utility files a plan or amended plan under
19		the provisions of subsection (e-20), in which case the minimum
20		spend for measures from such public customers shall be equal
21		to at least 30% of non-residential spending. Five percent of
22		the entire portfolio of cost-effective energy efficiency
23		measures may be granted to local government and municipal
24		corporations for market transformation initiatives.
25		Through calendar year 2026, the The utilities shall also
26		present a portfolio of energy efficiency measures

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1		proportionate to the share of total annual utility revenues in
2		Illinois from households at or below 150% of the poverty
3		level. Such programs shall be targeted to households with
4		incomes at or below 80% of area median income.
5		(e-7) Beginning January 1, 2027, the following
6		requirements shall be in effect for efficiency programs
7		targeted to low-income households. For the purposes of this
8		Section, "low-income households" means households with incomes
9		at or below 80% of the area median income. Utilities shall
10		leverage existing State and federal low-income weatherization
11		programs and delivery capacity to the extent practicable.
12		Utilities shall also prioritize contracting with
13		organizations, government agencies, and businesses with a
14		track record of delivering weatherization services in
15		low-income communities in this State to deliver any low-income
16		programs that are not integrated with State and federal
17		low-income weatherization programs.
18		(e-8) Beginning January 1, 2027, the following
19		requirements shall be in effect for efficiency programs
20		targeted to low-income households, except for single-fuel gas
21		utilities with less than 1,000,000 customers:
22		(1) The portion of the entire budget for efficiency
23		programs that is spent on efficiency programs for
24		low-income households shall be no less than the greater
25		of: (A) 25% or (B) five percentage points more than the
26		proportion of total annual gas sales to non-opt-out retail

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1		customers that are consumed by low-income households.
2		(2) The portion of spending on efficiency measures
3		that are targeted to low-income households that is
4		delivered through whole building weatherization programs
5		that comprehensively address building envelope efficiency
6		upgrade opportunities as well as other efficiency measures
7		shall be at least 80%.
8		(3) Utilities shall invest in health and safety
9		measures that are appropriate and necessary for
10		comprehensively weatherizing the single-family and
11		multi-family buildings of low-income households, with up
12		to 15% of income-qualified program spending made available
13		for such purposes.
14		(e-10) A utility providing approved energy efficiency
15		measures in this State shall be permitted to recover costs of
16		those measures through an automatic adjustment clause tariff
17		filed with and approved by the Commission. The tariff shall be
18		established outside the context of a general rate case and
19		shall be applicable to the utility's customers other than the
20		customers described in subsection (m) of this Section. Each
21		year the Commission shall initiate a review to reconcile any
22		amounts collected with the actual costs and to determine the
23		required adjustment to the annual tariff factor to match
24		annual expenditures.
25		(e-15) For those multi-year plans that commence prior to
26		January 1, 2018, each utility shall include, in its recovery

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1		of costs, the costs estimated for both the utility's and the
2		Department's implementation of energy efficiency measures.
3		Costs collected by the utility for measures implemented by the
4		Department shall be submitted to the Department pursuant to
5		Section 605-323 of the Civil Administrative Code of Illinois,
6		shall be deposited into the Energy Efficiency Portfolio
7		Standards Fund, and shall be used by the Department solely for
8		the purpose of implementing these measures. A utility shall
9		not be required to advance any moneys to the Department but
10		only to forward such funds as it has collected. The Department
11		shall report to the Commission on an annual basis regarding
12		the costs actually incurred by the Department in the
13		implementation of the measures. Any changes to the costs of
14		energy efficiency measures as a result of plan modifications
15		shall be appropriately reflected in amounts recovered by the
16		utility and turned over to the Department.
17		(e-20) The provisions of this Section shall be applicable
18		to multi-year plans that commence after the effective date of
19		this amendatory Act of the 104th General Assembly and are
20		submitted by single fuel service utilities on or before the
21		effective date of this amendatory Act of the 104th General
22		Assembly. A natural gas utility may propose, as part of its
23		submission of a multi-year plan, to increase the amount of
24		energy efficiency implemented in any multi-year planning
25		period above the level that can be achieved under the spending
26		cap set forth in subsection (d) of this Section. The first plan

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1		to increase energy efficiency may be submitted as an amendment
2		to the utility's plan for calendar years 2027 through 2029,
3		but any amended plans must be filed with the Commission by
4		March 1, 2026 or the effective date of this amendatory Act of
5		the 104th General Assembly, whichever is later. In addition to
6		the policy goals established in subsection (f), the Commission
7		shall consider, in determining the appropriateness of a
8		proposal, whether the multi-year plan at a minimum:
9		(1) identifies a cost-effective portfolio of measures
10		and specifies the natural gas savings that are reasonably
11		likely to be achieved by the utility;
12		(2) demonstrates that the plan or modified plan, at a
13		minimum, will result in a portfolio of energy efficiency
14		measures that will provide more natural gas savings than
15		would have been achieved in a plan subject to subsection
16		(c);
17		(3) demonstrates that the plan reflects efforts to
18		coordinate delivery of electric utility efficiency
19		programs where such coordination can reduce costs,
20		increase effectiveness of outreach to customers, and
21		increase savings. A gas utility may count electricity
22		savings toward its gas efficiency savings goals subject to
23		the following limitations:
24		(A) only electricity savings produced as a result
25		of the installation of a gas efficiency measure, such
26		as reductions in electricity consumption by gas

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1		furnace fans and electric air conditioners that
2		results from the installation of insulation measures
3		that reduce gas used for space heating, may be
4		counted;
5		(B) such electricity savings may only be counted
6		when they are generated in service territories not
7		served by electric utilities subject to Section
8		8-103B;
9		(C) no more than 5% of the total savings claimed
10		toward a gas utility's savings goal may be from such
11		electricity savings. For the purposes of this Section,
12		a kilowatt-hour of savings is equal to 0.03412 gas
13		therms;
14		(4) demonstrates whether an increase in funding is
15		necessary to meet the proposed increase in the amount of
16		energy efficiency;
17		(5) prioritizes income-qualified measures and
18		weatherization measures; and
19		(6) demonstrates that the multi-year plan strikes a
20		reasonable balance between the goals of the following:
21		(A) increasing cost-effective efficiency savings
22		and related greenhouse gas emission reductions;
23		(B) reducing overall gas system costs, recognizing
24		that efficiency investments reduce usage and, in turn,
25		the potential need for system investments over the
26		long-term;

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1		(C) increasing energy affordability, especially
2		for low-income customers;
3		(D) within the residential sector, prioritizing
4		investment in weatherization and other measures that
5		reduce heating loads over gas equipment measures; and
6		(E) providing a diverse cross-section of
7		opportunities for customers of all rate classes to
8		participate in efficiency programs.
9		For single-fuel gas utilities with less than 1,000,000
10		customers, the following requirements shall be in effect for
11		efficiency programs targeted to low-income households:
12		(1) For gas utilities with greater than 300,000
13		customers, the portion of the entire budget for efficiency
14		programs that is spent on efficiency programs for
15		low-income households shall be no less than the greater of
16		(A) 25% or (B) five percentage points more than the
17		proportion of total annual gas sales to non-opt-out retail
18		customers that are consumed by low-income households. For
19		gas utilities with 300,000 or fewer customers, the portion
20		of the entire budget for efficiency programs that is spent
21		on efficiency programs for low-income households shall be
22		no less than the greater of (A) 15% or (B) five percentage
23		points more than the proportion of total annual gas sales
24		to non-opt-out retail customers that are consumed by
25		low-income households.
26		(2) The portion of spending on efficiency measures

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1		targeted to low-income households that shall be delivered
2		through whole building weatherization programs that
3		comprehensively address building envelope efficiency
4		upgrade opportunities as well as other efficiency measures
5		shall be at least 80%.
6		(3) Utilities shall invest in health and safety
7		measures appropriate and necessary for comprehensively
8		weatherizing the single-family and multi-family buildings
9		of low-income households, with up to 15% of
10		income-qualified program spending made available for such
11		purposes.
12		As part of its order approving the plan or modified plan,
13		the Commission is authorized to:
14		(1) adjust the limitation on the amount of energy
15		efficiency measures implemented pursuant to subsection (d)
16		to the extent necessary to meet the increase in the amount
17		of energy efficiency approved by the Commission pursuant
18		to this subsection (e-20);
19		(2) adjust the public sector spending requirements
20		pursuant to subsection (e-5);
21		(3) adopt an incentive mechanism for the utility to
22		meet or exceed the goals associated with its proposed
23		multi-year plan if the utility meets or exceeds the
24		following minimum requirements:
25		(A) the utility proposes a plan budget over the
26		applicable multi-year period that is equal to or

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1		greater than 5% of the amounts paid by non-opt-out
2		retail customers in connection with natural gas
3		service in the applicable multi-year period;
4		(B) for efficiency program years 2027 through
5		2029, the utility achieves average incremental annual
6		savings of at least 0.7% of total average annual gas
7		sales to non-opt-out retail customers over the years
8		2023 through 2025. For multi-year efficiency program
9		plans beginning after 2029, achieving average
10		incremental annual savings of at least 0.8% of total
11		average annual gas sales to non-opt-out retail
12		customers during the 3-year period ending 2 years
13		prior to the first year of the plan. In all multi-year
14		periods, the minimum incremental annual savings
15		requirement shall be reduced by 0.01 percentage points
16		for every 1 percentage point increase in low-income or
17		moderate-income spending above the minimum levels
18		required by subsection (e-5). In no event shall the
19		minimum incremental annual savings requirement be
20		reduced by more than 0.10 percentage points even if
21		low-income or moderate-income spending is increased by
22		more than 10 percentage points above the minimum
23		levels required by subsection (e-5). The Commission
24		may reduce the magnitude of the minimum savings
25		requirements under this subparagraph (B) if the
26		utility can demonstrate that it is not possible to

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1		achieve them with a budget equal to 5% of revenues from
2		eligible customers while meeting other minimum
3		requirements. If a utility attempts to demonstrate
4		that it cannot meet the minimum savings requirements
5		in this paragraph with a budget equal to 5% of revenues
6		from eligible customers, and the Commission finds that
7		the utility has not made a sufficiently compelling
8		demonstration, the utility may withdraw its plan and
9		file a revised plan;
10		(C) the utility achieves an average savings life
11		of at least 12 years. Average savings lives may be
12		shorter than the average operational lives of measures
13		if the measures do not produce savings in every year in
14		which they operate or if the savings that measures
15		produce decline during their operational lives; and
16		(D) the utility spends at least 67% of all
17		financial incentive dollars on efficiency measures
18		that (1) reduce the space heating loads of buildings
19		through improvements such as to building envelopes,
20		ventilation systems, space heating distribution
21		systems, and space heating system controls; (2) reduce
22		the water heating loads of buildings such as through
23		insulation of hot water pipes, recovery and reuse of
24		heat from waste water and reductions in the amount of
25		hot water required to meet customer needs; or (3)
26		reduce the process heat loads of industrial

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1		facilities. Any spending on health and safety measures
2		shall count toward this requirement. No financial
3		incentive spending on furnaces, boilers, water
4		heaters, and other gas-consuming equipment may be
5		counted toward this requirement; and
6		(4) for modified plans, require a compliance filing
7		from the utility to adjust budgets and natural gas savings
8		targets, if necessary, to reflect the final level of
9		customers opting out under subsection (m-1).
10		For the purposes of this subsection (e-20):
11		"Average savings life" means (i) the savings that will be
12		realized as a result of a utility's efficiency programs over
13		the lives of all efficiency measures divided by (ii) the
14		savings that will be produced in the first year after such
15		measures are installed.
16		"Moderate-income" means income between 80% of area median
17		income and 300% of the federal poverty limit.
18		(f) No later than October 1, 2010, each gas utility shall
19		file an energy efficiency plan with the Commission to meet the
20		energy efficiency standards through May 31, 2014. No later
21		than October 1, 2013, each gas utility shall file an energy
22		efficiency plan with the Commission to meet the energy
23		efficiency standards through May 31, 2017. Beginning in 2017
24		and every 4 years thereafter, each utility shall file an
25		energy efficiency plan with the Commission to meet the energy
26		efficiency standards for the next applicable 4-year period

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

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

SB0025 Enrolled - 619 - LRB104 07069 BAB 17106 b
1		January 1, 2018, coordinate with the Department to present
2		a portfolio of energy efficiency measures proportionate to
3		the share of total annual utility revenues in Illinois
4		from households at or below 150% of the poverty level.
5		Such programs shall be targeted to households with incomes
6		at or below 80% of area median income.
7		(5) Demonstrate that its overall portfolio of energy
8		efficiency measures, not including low-income programs
9		described in item (4) of this subsection (f) and
10		subsection (e-5) of this Section, are cost-effective using
11		the total resource cost test and represent a diverse cross
12		section of opportunities for customers of all rate classes
13		to participate in the programs.
14		(6) Demonstrate that a gas utility affiliated with an
15		electric utility that is required to comply with Section
16		8-103 or 8-103B of this Act has integrated gas and
17		electric efficiency measures into a single program that
18		reduces program or participant costs and appropriately
19		allocates costs to gas and electric ratepayers. For those
20		multi-year plans that commence prior to January 1, 2018,
21		the Department shall integrate all gas and electric
22		programs it delivers in any such utilities' service
23		territories, unless the Department can show that
24		integration is not feasible or appropriate.
25		(7) Include a proposed cost recovery tariff mechanism
26		to fund the proposed energy efficiency measures and to

SB0025 Enrolled - 620 - LRB104 07069 BAB 17106 b
1		ensure the recovery of the prudently and reasonably
2		incurred costs of Commission-approved programs.
3		(8) Provide for quarterly status reports tracking
4		implementation of and expenditures for the utility's
5		portfolio of measures and, if applicable, the Department's
6		portfolio of measures, an annual independent review, and a
7		full independent evaluation of the multi-year results of
8		the performance and the cost-effectiveness of the
9		utility's and, if applicable, Department's portfolios of
10		measures and broader net program impacts and, to the
11		extent practical, for adjustment of the measures on a
12		going forward basis as a result of the evaluations. The
13		resources dedicated to evaluation shall not exceed 3% of
14		portfolio resources in any given multi-year period.
15		(g) No more than 3% of expenditures on energy efficiency
16		measures may be allocated for demonstration of breakthrough
17		equipment and devices.
18		(h) Illinois natural gas utilities that are affiliated by
19		virtue of a common parent company may, at the utilities'
20		request, be considered a single natural gas utility for
21		purposes of complying with this Section.
22		(i) If, after 3 years, a gas utility fails to meet the
23		efficiency standard specified in subsection (c) of this
24		Section as modified by subsection (d), then it shall make a
25		contribution to the Low-Income Home Energy Assistance Program.
26		The total liability for failure to meet the goal shall be

SB0025 Enrolled - 621 - LRB104 07069 BAB 17106 b
1		assessed as follows:
2		(1) a large gas utility shall pay $600,000;
3		(2) a medium gas utility shall pay $400,000; and
4		(3) a small gas utility shall pay $200,000.
5		For purposes of this Section, (i) a "large gas utility" is
6		a gas utility that on December 31, 2008, served more than
7		1,500,000 gas customers in Illinois; (ii) a "medium gas
8		utility" is a gas utility that on December 31, 2008, served
9		fewer than 1,500,000, but more than 500,000 gas customers in
10		Illinois; and (iii) a "small gas utility" is a gas utility that
11		on December 31, 2008, served fewer than 500,000 and more than
12		100,000 gas customers in Illinois. The costs of this
13		contribution may not be recovered from ratepayers.
14		If a gas utility fails to meet the efficiency standard
15		specified in subsection (c) of this Section, as modified by
16		subsection (d) of this Section, in any 2 consecutive
17		multi-year planning periods, then the responsibility for
18		implementing the utility's energy efficiency measures shall be
19		transferred to an independent program administrator selected
20		by the Commission. Reasonable and prudent costs incurred by
21		the independent program administrator to meet the efficiency
22		standard specified in subsection (c) of this Section, as
23		modified by subsection (d) of this Section, may be recovered
24		from the customers of the affected gas utilities, other than
25		customers described in subsection (m) of this Section. The
26		utility shall provide the independent program administrator

SB0025 Enrolled - 622 - LRB104 07069 BAB 17106 b
1		with all information and assistance necessary to perform the
2		program administrator's duties including but not limited to
3		customer, account, and energy usage data, and shall allow the
4		program administrator to include inserts in customer bills.
5		The utility may recover reasonable costs associated with any
6		such assistance.
7		(j) No utility shall be deemed to have failed to meet the
8		energy efficiency standards to the extent any such failure is
9		due to a failure of the Department.
10		(k) Not later than January 1, 2012, the Commission shall
11		develop and solicit public comment on a plan to foster
12		statewide coordination and consistency between statutorily
13		mandated natural gas and electric energy efficiency programs
14		to reduce program or participant costs or to improve program
15		performance. Not later than September 1, 2013, the Commission
16		shall issue a report to the General Assembly containing its
17		findings and recommendations.
18		(l) This Section does not apply to a gas utility that on
19		January 1, 2009, provided gas service to fewer than 100,000
20		customers in Illinois.
21		(m) Subsections (a) through (k) of this Section do not
22		apply to customers of a natural gas utility that have a North
23		American Industry Classification System code number that is
24		22111 or any such code number beginning with the digits 31, 32,
25		or 33 and (i) annual usage in the aggregate of 4 million therms
26		or more within the service territory of the affected gas

SB0025 Enrolled - 623 - LRB104 07069 BAB 17106 b
1		utility or with aggregate usage of 8 million therms or more in
2		this State and complying with the provisions of item (l) of
3		this subsection (m); or (ii) using natural gas as feedstock
4		and meeting the usage requirements described in item (i) of
5		this subsection (m), to the extent such annual feedstock usage
6		is greater than 60% of the customer's total annual usage of
7		natural gas.
8		(1) Customers described in this subsection (m) of this
9		Section shall apply, on a form approved on or before
10		October 1, 2009 by the Department, to the Department to be
11		designated as a self-directing customer ("SDC") or as an
12		exempt customer using natural gas as a feedstock from
13		which other products are made, including, but not limited
14		to, feedstock for a hydrogen plant, on or before the 1st
15		day of February, 2010. Thereafter, application may be made
16		not less than 6 months before the filing date of the gas
17		utility energy efficiency plan described in subsection (f)
18		of this Section; however, a new customer that commences
19		taking service from a natural gas utility after February
20		1, 2010 may apply to become a SDC or exempt customer up to
21		30 days after beginning service. Customers described in
22		this subsection (m) that have not already been approved by
23		the Department may apply to be designated a self-directing
24		customer or exempt customer, on a form approved by the
25		Department, between September 1, 2013 and September 30,
26		2013. Customer applications that are approved by the

SB0025 Enrolled - 624 - LRB104 07069 BAB 17106 b
1		Department under this amendatory Act of the 98th General
2		Assembly shall be considered to be a self-directing
3		customer or exempt customer, as applicable, for the
4		current 3-year planning period effective December 1, 2013.
5		Such application shall contain the following:
6		(A) the customer's certification that, at the time
7		of its application, it qualifies to be a SDC or exempt
8		customer described in this subsection (m) of this
9		Section;
10		(B) in the case of a SDC, the customer's
11		certification that it has established or will
12		establish by the beginning of the utility's multi-year
13		planning period commencing subsequent to the
14		application, and will maintain for accounting
15		purposes, an energy efficiency reserve account and
16		that the customer will accrue funds in said account to
17		be held for the purpose of funding, in whole or in
18		part, energy efficiency measures of the customer's
19		choosing, which may include, but are not limited to,
20		projects involving combined heat and power systems
21		that use the same energy source both for the
22		generation of electrical or mechanical power and the
23		production of steam or another form of useful thermal
24		energy or the use of combustible gas produced from
25		biomass, or both;
26		(C) in the case of a SDC, the customer's

SB0025 Enrolled - 625 - LRB104 07069 BAB 17106 b
1		certification that annual funding levels for the
2		energy efficiency reserve account will be equal to 2%
3		of the customer's cost of natural gas, composed of the
4		customer's commodity cost and the delivery service
5		charges paid to the gas utility, or $150,000,
6		whichever is less;
7		(D) in the case of a SDC, the customer's
8		certification that the required reserve account
9		balance will be capped at 3 years' worth of accruals
10		and that the customer may, at its option, make further
11		deposits to the account to the extent such deposit
12		would increase the reserve account balance above the
13		designated cap level;
14		(E) in the case of a SDC, the customer's
15		certification that by October 1 of each year,
16		beginning no sooner than October 1, 2012, the customer
17		will report to the Department information, for the
18		12-month period ending May 31 of the same year, on all
19		deposits and reductions, if any, to the reserve
20		account during the reporting year, and to the extent
21		deposits to the reserve account in any year are in an
22		amount less than $150,000, the basis for such reduced
23		deposits; reserve account balances by month; a
24		description of energy efficiency measures undertaken
25		by the customer and paid for in whole or in part with
26		funds from the reserve account; an estimate of the

SB0025 Enrolled - 626 - LRB104 07069 BAB 17106 b
1		energy saved, or to be saved, by the measure; and that
2		the report shall include a verification by an officer
3		or plant manager of the customer or by a registered
4		professional engineer or certified energy efficiency
5		trade professional that the funds withdrawn from the
6		reserve account were used for the energy efficiency
7		measures;
8		(F) in the case of an exempt customer, the
9		customer's certification of the level of gas usage as
10		feedstock in the customer's operation in a typical
11		year and that it will provide information establishing
12		this level, upon request of the Department;
13		(G) in the case of either an exempt customer or a
14		SDC, the customer's certification that it has provided
15		the gas utility or utilities serving the customer with
16		a copy of the application as filed with the
17		Department;
18		(H) in the case of either an exempt customer or a
19		SDC, certification of the natural gas utility or
20		utilities serving the customer in Illinois including
21		the natural gas utility accounts that are the subject
22		of the application; and
23		(I) in the case of either an exempt customer or a
24		SDC, a verification signed by a plant manager or an
25		authorized corporate officer attesting to the
26		truthfulness and accuracy of the information contained

SB0025 Enrolled - 627 - LRB104 07069 BAB 17106 b
1		in the application.
2		(2) The Department shall review the application to
3		determine that it contains the information described in
4		provisions (A) through (I) of item (1) of this subsection
5		(m), as applicable. The review shall be completed within
6		30 days after the date the application is filed with the
7		Department. Absent a determination by the Department
8		within the 30-day period, the applicant shall be
9		considered to be a SDC or exempt customer, as applicable,
10		for all subsequent multi-year planning periods, as of the
11		date of filing the application described in this
12		subsection (m). If the Department determines that the
13		application does not contain the applicable information
14		described in provisions (A) through (I) of item (1) of
15		this subsection (m), it shall notify the customer, in
16		writing, of its determination that the application does
17		not contain the required information and identify the
18		information that is missing, and the customer shall
19		provide the missing information within 15 working days
20		after the date of receipt of the Department's
21		notification.
22		(3) The Department shall have the right to audit the
23		information provided in the customer's application and
24		annual reports to ensure continued compliance with the
25		requirements of this subsection. Based on the audit, if
26		the Department determines the customer is no longer in

SB0025 Enrolled - 628 - LRB104 07069 BAB 17106 b
1		compliance with the requirements of items (A) through (I)
2		of item (1) of this subsection (m), as applicable, the
3		Department shall notify the customer in writing of the
4		noncompliance. The customer shall have 30 days to
5		establish its compliance, and failing to do so, may have
6		its status as a SDC or exempt customer revoked by the
7		Department. The Department shall treat all information
8		provided by any customer seeking SDC status or exemption
9		from the provisions of this Section as strictly
10		confidential.
11		(4) Upon request, or on its own motion, the Commission
12		may open an investigation, no more than once every 3 years
13		and not before October 1, 2014, to evaluate the
14		effectiveness of the self-directing program described in
15		this subsection (m).
16		Customers described in this subsection (m) that applied to
17		the Department on January 3, 2013, were approved by the
18		Department on February 13, 2013 to be a self-directing
19		customer or exempt customer, and receive natural gas from a
20		utility that provides gas service to at least 500,000 retail
21		customers in Illinois and electric service to at least
22		1,000,000 retail customers in Illinois shall be considered to
23		be a self-directing customer or exempt customer, as
24		applicable, for the current 3-year planning period effective
25		December 1, 2013.
26		(m-1) For utilities that file an amended plan for the

SB0025 Enrolled - 629 - LRB104 07069 BAB 17106 b
1		period covering calendar years 2027 through 2029, and for all
2		utilities for all calendar years covered by a multi-year plan
3		commencing on or after January 1, 2030, subsections (a)
4		through (k) of this Section do not apply to eligible customers
5		of a natural gas utility that have chosen to opt out of
6		multi-year plans.
7		(1) For purposes of this subsection (m-1), "eligible
8		customer" means any retail customer of a natural gas
9		utility, except for federal, State, municipal and other
10		public customers, with a North American Industry
11		Classification System code number that is 22111 or any
12		such code number beginning with the digits 31, 32, or 33
13		and (i) annual usage in the aggregate of 4,000,000 therms
14		or more within the service territory of the affected gas
15		utility or with aggregate usage of 8,000,000 therms or
16		more in this State; or (ii) using natural gas as feedstock
17		and meeting the usage requirements described in item (i)
18		of this paragraph (1), to the extent such annual feedstock
19		usage is greater than 60% of the customer's total annual
20		usage of natural gas. A determination of whether this
21		subsection is applicable to a customer shall be made for
22		each multi-year plan beginning after January 1, 2026. The
23		criteria for determining whether this subsection is
24		applicable shall be the 12 consecutive billing periods
25		prior to the start of the first year of each such
26		multi-year plan.

SB0025 Enrolled - 630 - LRB104 07069 BAB 17106 b
1		(2) Within 45 days after the effective date of this
2		amendatory Act of the 104th General Assembly, the
3		Commission shall prescribe the form for notice required
4		for opting out of energy efficiency programs. Within 120
5		days after the Commission's initial issuance of the form
6		for notice, customers described in paragraph (1) of this
7		subsection (m-1) may submit completed forms to the natural
8		gas utility. Thereafter, forms must be submitted to the
9		natural gas utility not less than 6 months before the
10		filing date of the gas utility energy efficiency plan
11		described in subsection (f) of this Section; however, a
12		new customer that commences taking service from a natural
13		gas utility after January 1, 2026 may submit a form up to
14		30 days after beginning service. The form for notice for
15		opting out of natural gas energy efficiency programs shall
16		contain the following:
17		(A) a statement indicating that the customer has
18		elected to opt-out;
19		(B) the account numbers for the customer accounts
20		to which the opt out shall apply;
21		(C) the mailing address associated with each
22		customer account identified under subparagraph (B);
23		(D) the customer's certification that, at the time
24		its form was submitted, it qualifies as an eligible
25		customer, as described in paragraph (1) of this
26		subsection (m-1);

SB0025 Enrolled - 631 - LRB104 07069 BAB 17106 b
1		(E) an American Society of Heating, Refrigerating,
2		and Air Conditioning Engineers (ASHRAE) level 2 or
3		higher audit report conducted by an independent
4		third-party expert identifying cost-effective energy
5		efficiency project opportunities that could be
6		invested in over the next 10 years. A customer with a
7		specialized process may use a self-audit process in
8		lieu of an ASHRAE audit;
9		(F) a description of the customer's plans to
10		reallocate funds toward internal energy efficiency
11		efforts identified in the subparagraph (E) report,
12		including, but not limited to: (i) strategic energy
13		management or other programs, including descriptions
14		of targeted buildings, equipment and operations; (ii)
15		eligible energy efficiency measures; and (iii)
16		expected energy savings, itemized by technology. If
17		the subparagraph (E) audit report identifies that the
18		customer currently utilizes the best available energy
19		efficient technology, equipment, programs, and
20		operations, the customer may provide a statement that
21		more efficient technology, equipment, programs, and
22		operations are not reasonably available as a means of
23		satisfying this subparagraph (F); and
24		(G) a verification signed by a plant manager or an
25		authorized corporate officer attesting to the
26		truthfulness and accuracy of the information contained

SB0025 Enrolled - 632 - LRB104 07069 BAB 17106 b
1		in the application.
2		(3) Upon receipt of a properly and timely noticed
3		request for opt out submitted by an eligible large private
4		energy customer, the natural gas utility shall grant the
5		request and file the request with the Commission, and,
6		beginning January 1 of the first year of the next
7		multi-year energy efficiency plan cycle, the opted out
8		customer shall no longer be assessed the costs of the plan
9		and shall be prohibited from participating in that
10		multi-year plan cycle to give the natural gas utility the
11		certainty to design program plan proposals.
12		(4) The request to opt out is only valid for the
13		requested plan cycle. An eligible large private energy
14		customer must also request to opt out for future energy
15		efficiency plan cycles, otherwise the customer will be
16		included in the future energy efficiency plan cycle.
17		(n) The applicability of this Section to customers
18		described in subsection (m) of this Section is conditioned on
19		the existence of the SDC program. In no event will any
20		provision of this Section apply to such customers after
21		January 1, 2020.
22		(o) Utilities' 3-year energy efficiency plans approved by
23		the Commission on or before the effective date of this
24		amendatory Act of the 99th General Assembly for the period
25		June 1, 2014 through May 31, 2017 shall continue to be in force
26		and effect through December 31, 2017 so that the energy

SB0025 Enrolled - 633 - LRB104 07069 BAB 17106 b
1		efficiency programs set forth in those plans continue to be
2		offered during the period June 1, 2017 through December 31,
3		2017. Each utility is authorized to increase, on a pro rata
4		basis, the energy savings goals and budgets approved in its
5		plan to reflect the additional 7 months of the plan's
6		operation.
7		(Source: P.A. 103-613, eff. 7-1-24.)
8		(220 ILCS 5/8-512)
9		Sec. 8-512. Renewable energy access plan.
10		(a) It is the policy of this State to promote
11		cost-effective transmission system development that ensures
12		reliability of the electric transmission system, lowers carbon
13		emissions, minimizes long-term costs for consumers, and
14		supports the electric policy goals of this State. The General
15		Assembly finds that:
16		(1) Transmission planning, primarily for reliability
17		purposes, but also for economic and public policy reasons
18		is conducted by regional transmission organizations in
19		which transmission-owning Illinois utilities and other
20		stakeholders are members.
21		(2) Order No. 1000 of the Federal Energy Regulatory
22		Commission requires regional transmission organizations to
23		plan for transmission system needs in light of State
24		public policies and to accept input from states during the
25		transmission system planning processes.

SB0025 Enrolled - 634 - LRB104 07069 BAB 17106 b
1		(3) The State of Illinois does not currently have a
2		comprehensive power and environmental policy planning
3		process to identify transmission infrastructure needs that
4		can serve as a vital input into the regional and
5		interregional transmission organization planning
6		processes conducted under Order No. 1000 and other laws
7		and regulations.
8		(4) This State is an electricity generation and power
9		transmission hub, and can leverage that position to invest
10		in infrastructure that enables new and existing Illinois
11		generators to meet the public policy goals of the State of
12		Illinois and of interconnected states while
13		cost-effectively supporting tens of thousands of jobs in
14		the renewable energy sector in this State.
15		(5) The nation has a need to readily access this
16		State's low-cost, clean electric power, and this State
17		also desires access to clean energy resources in other
18		states to develop and support its low-carbon economy and
19		keep electricity prices low in Illinois and interconnected
20		States.
21		(6) Existing transmission infrastructure may constrain
22		the State's achievement of 100% renewable energy by 2050,
23		the accelerated adoption of electric vehicles in a just
24		and equitable way, and electrification of additional
25		sectors of the Illinois economy.
26		(7) Transmission system congestion within this State

SB0025 Enrolled - 635 - LRB104 07069 BAB 17106 b
1		and the regional transmission organizations serving this
2		State limits the ability of this State's existing and new
3		electric generation facilities that do not emit carbon
4		dioxide, including renewable energy resources and zero
5		emission facilities, to serve the public policy goals of
6		this State and other states, which constrains investment
7		in this State.
8		(8) Investment in infrastructure to support existing
9		and new electric generation facilities that do not emit
10		carbon dioxide, including renewable energy resources and
11		zero emission facilities, stimulates significant economic
12		development and job growth in this State, as well as
13		creates environmental and public health benefits in this
14		State.
15		(9) Creating a forward-looking plan for this State's
16		electric transmission infrastructure, as opposed to
17		relying on case-by-case development and repeated marginal
18		upgrades, will achieve a lower-cost system for Illinois'
19		electricity customers. A forward-looking plan can also
20		help integrate and achieve a comprehensive set of
21		objectives and multiple state, regional, and national
22		policy goals.
23		(10) Alternatives to overhead electric transmission
24		lines can achieve cost-effective resolution of system
25		impacts and warrant investigation of the circumstances
26		under which those alternatives should be considered and

SB0025 Enrolled - 636 - LRB104 07069 BAB 17106 b
1		approved. The alternatives are likely to be beneficial as
2		investment in electric transmission infrastructure moves
3		forward.
4		(11) Because transmission planning is conducted
5		primarily by the regional transmission organizations, the
6		Commission should be advocating for the State's interests
7		at the regional transmission organizations to ensure that
8		such planning facilitates the State's policies and goals,
9		including overall consumer savings, power system
10		reliability, economic development, environmental
11		improvement, and carbon reduction.
12		(12) Advanced transmission technologies have an
13		important role to play in meeting the State's clean energy
14		goals. For the purposes of this Section, "advanced
15		transmission technology" is hardware or software that
16		provides cost-effective increases to the capacity,
17		efficiency, or reliability of existing transmission
18		infrastructure, and includes, but is not limited to: (i)
19		technology that dynamically adjusts the rated capacity of
20		transmission lines based on real-time conditions; (ii)
21		advanced power flow controls used to actively control the
22		flow of electricity across transmission lines to optimize
23		usage or relieve congestion; (iii) software or hardware
24		used to identify optimal transmission grid configurations
25		or enable routing power flows around congestion points;
26		and (iv) advanced transmission line conductors that have a

SB0025 Enrolled - 637 - LRB104 07069 BAB 17106 b
1		direct current electrical resistance at least 10% lower
2		than existing conductors of a similar diameter on the
3		transmission system.
4		(b) Consistent with the findings identified in subsection
5		(a), the Commission shall open an investigation to develop and
6		adopt an initial a renewable energy access plan no later than
7		December 31, 2022. To assist and support the Commission in the
8		development of the plan, the Commission shall retain the
9		services of technical and policy experts with relevant fields
10		of expertise, solicit technical and policy analysis from the
11		public, and provide for a 120-day open public comment period
12		after publication of a draft report, which shall be published
13		no later than 90 days after the comment period ends. The plan
14		shall, at a minimum, do the following:
15		(1) designate renewable energy access plan zones
16		throughout this State in areas in which renewable energy
17		resources and suitable land areas are sufficient for
18		developing generating capacity from renewable energy
19		technologies;
20		(2) develop a plan to achieve transmission capacity
21		necessary to deliver the electric output from renewable
22		energy technologies in the renewable energy access plan
23		zones to customers in Illinois and other states in a
24		manner that is most beneficial and cost-effective to
25		customers;
26		(3) use this State's position as an electricity

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1		generation and power transmission hub to create new
2		investment in this State's renewable energy resources;
3		(4) consider programs, policies, and electric
4		transmission projects that can be adopted within this
5		State that promote the cost-effective delivery of power
6		from renewable energy resources interconnected to the bulk
7		electric system to meet the renewable portfolio standard
8		targets under subsection (c) of Section 1-75 of the
9		Illinois Power Agency Act;
10		(5) consider proposals to improve regional
11		transmission organizations' regional and interregional
12		system planning processes, especially proposals that
13		reduce costs and emissions, create jobs, and increase
14		State and regional power system reliability to prevent
15		high-cost outages that can endanger lives, and analyze of
16		how those proposals would improve reliability and
17		cost-effective delivery of electricity in Illinois and the
18		region;
19		(6) make findings and policy recommendations based on
20		technical and policy analysis regarding locations of
21		renewable energy access plan zones and the transmission
22		system developments needed to cost-effectively achieve the
23		public policy goals identified herein;
24		(6.5) make findings and policy recommendations based
25		on analysis regarding the impact of converting non-powered
26		dams to hydropower dams relative to the alternative

SB0025 Enrolled - 639 - LRB104 07069 BAB 17106 b
1		renewable energy resources; and
2		(7) present the Commission's conclusions and proposed
3		recommendations based on its analysis and use the findings
4		and policy recommendations to determine actions that the
5		Commission should take.
6		(c) No later than December 31, 2025, and updated no later
7		than 180 days after the effective date of this amendatory Act
8		of the 104th General Assembly to incorporate changes pursuant
9		to this amendatory Act of the 104th General Assembly, and
10		every other year thereafter starting in 2028, the Commission
11		shall open an investigation to develop and adopt a an updated
12		renewable energy access plan update that considers electric
13		transmission projects, transmission policies, transmission
14		alternatives, advanced transmission technologies, other ways
15		to expand capacity on existing or future transmission, and
16		transmission headroom and, at a minimum, : evaluates the
17		implementation and effectiveness of the renewable energy
18		access plan, recommends improvements to the renewable energy
19		access plan, and provides changes to transmission capacity
20		necessary to deliver electric output from the renewable energy
21		access plan zones.
22		(1) evaluates the implementation and effectiveness of
23		the renewable energy access plan;
24		(2) recommends improvements to the renewable energy
25		access plan;
26		(3) includes updated inputs and assumptions developed

SB0025 Enrolled - 640 - LRB104 07069 BAB 17106 b
1		under the integrated resource plan developed and approved
2		pursuant to Section 16-201 and Section 16-202;
3		(4) may request utilities and other parties to
4		specifically identify all elements of the existing
5		transmission system where advanced transmission
6		technologies are likely to achieve enhanced system
7		resilience or reliability, reduce potential siting
8		conflicts or land impacts from the development of new
9		transmission lines, promote the cost-effective delivery of
10		power from renewable energy resources interconnected to
11		the bulk electric system, enable the interconnection of
12		renewable energy resources, or reduce curtailment of
13		renewable energy resources. The plan must identify all
14		elements of the existing transmission system which have
15		experienced capacity constraints or congestion within the
16		prior 2 years and explain whether any advanced
17		transmission technology could reduce or resolve the
18		capacity constraint or congestion;
19		(5) includes an evaluation of identified and proposed
20		transmission projects, including proposed advanced
21		transmission technology projects, based on independent
22		analysis of costs and benefits, including customer bill
23		impacts over the life of the project and achievement of
24		State clean energy goals. Projects shall be evaluated in
25		coordination with other proposals, and may include a
26		combined evaluation of portfolios of projects;

SB0025 Enrolled - 641 - LRB104 07069 BAB 17106 b
1		(6) develops a recommended list of transmission
2		projects and advanced transmission technology projects
3		that achieve the clean energy public policy objectives of
4		the State. Nothing in this Section shall limit the
5		recommended list of transmission projects to those
6		initially proposed. However, no transmission or advanced
7		transmission technology project can be included in the
8		recommended list unless evaluated; and
9		(7) considers additional mechanisms designed to
10		capture the potential value of geographically diverse
11		resources that proposed interregional transmission
12		projects may provide.
13		The Commission may evaluate options for implementation of
14		the recommended list of transmission projects and advanced
15		transmission technology projects that achieve the clean energy
16		public policy objectives of the State, including through the
17		use of a state agreement approach or a similar structure made
18		available through the relevant regional transmission
19		organizations, and approves final recommendations on
20		implementation.
21		The Commission may invite any interested party to identify
22		transmission projects, including any associated network
23		upgrades, necessary to facilitate achievement of the goals of
24		the plan and the most recently approved integrated resource
25		plan. Proposals for projects shall include a description of
26		each project; a proposed target date for completion; an

SB0025 Enrolled - 642 - LRB104 07069 BAB 17106 b
1		estimated timeline for development; the energy, capacity, and
2		generation profile of renewable generation and energy storage
3		enabled by the project; anticipated new loads served by the
4		project; the proposed technology used, including the use of
5		any advanced transmission technologies; and the status of any
6		permits or approvals necessary. For projects with a target
7		completion date of within 5 years from the date of proposal,
8		the proposal must also include an estimated cost of the
9		project and the proposed routing corridor. The Commission
10		shall aim to complete the updated plan investigation within 12
11		months of opening.
12		(d) Each transmission-owning State utility serving more
13		than 200,000 customers in this State may prepare a plan for
14		integrating advanced transmission technologies into the
15		utility's existing transmission system. The plan must identify
16		all elements of the existing transmission system where
17		advanced transmission technologies are likely to achieve any
18		of the following purposes:
19		(1) enhance system resilience or reliability;
20		(2) reduce potential siting conflicts or land impacts
21		from the development of new transmission lines;
22		(3) promote the cost-effective delivery of power from
23		renewable energy resources interconnected to the bulk
24		electric system to meet the renewable portfolio standard
25		targets under subsection (c) of Section 1-75 of the
26		Illinois Power Agency Act;

SB0025 Enrolled - 643 - LRB104 07069 BAB 17106 b
1		(4) enable the interconnection of renewable energy
2		resources to meet the renewable portfolio standard targets
3		under subsection (c) of Section 1-75 of the Illinois Power
4		Agency Act; or
5		(5) reduce curtailment of renewable or zero-carbon
6		resources.
7		The plan must identify all elements of the existing
8		transmission system which have experienced capacity
9		constraints or congestion within the prior 2 years and explain
10		whether any advanced transmission technology could reduce or
11		resolve the capacity constraint or congestion. Each
12		transmission-owning State utility may submit an advanced
13		transmission technology integration plan to the Commission for
14		consideration as part of the Commission's updated renewable
15		energy access plan investigation under subsection (c). In the
16		Commission's updated renewable energy access plan, the
17		Commission may evaluate, request modifications for, change the
18		timelines of implementation for, and determine the next steps
19		for each advanced transmission integration plan.
20		(e) Each transmission-owning State utility serving more
21		than 200,000 customers in this State may conduct a
22		comprehensive Transmission Headroom Study that shall identify,
23		at a minimum, the points of interconnection with unused,
24		existing transmission headroom on the State system, including
25		available capacity behind existing, underutilized points of
26		interconnection, and the amount of available headroom in

SB0025 Enrolled - 644 - LRB104 07069 BAB 17106 b
1		megawatts at each identified point of interconnection. Each
2		transmission-owning State utility may submit a Transmission
3		Headroom Study to the Commission for consideration as part of
4		the Commission's updated renewable energy access plan
5		investigation under subsection (c).
6		(f) The Commission shall approve an updated renewable
7		energy access plan if it finds that, at a minimum, the evidence
8		in the investigation meets the criteria outlined in subsection
9		(c) and demonstrates that the updated plan will support the
10		clean energy public policy objectives of the State.
11		(g) The Commission shall notify the applicable regional
12		transmission organizations and utilities of any final
13		recommendations to support the clean energy public policy
14		objectives of the State.
15		(h) Nothing in this Section alters the rights of
16		transmission utilities (i) under rates on file with the
17		Federal Energy Regulatory Commission or the Illinois Commerce
18		Commission, (ii) under orders and determinations of the
19		Federal Energy Regulatory Commission or a regional
20		transmission organization, or (iii) under applicable State
21		laws and policies.
22		(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
23		(220 ILCS 5/8-513 new)
24		Sec. 8-513. Thermal Energy Network Pilot Program.
25		(a) The Commission shall coordinate with the Illinois

SB0025 Enrolled - 645 - LRB104 07069 BAB 17106 b
1		Finance Authority, in its role as Climate Bank for the State,
2		to leverage any available federal funding to support thermal
3		energy network pilot projects through the provision of grants
4		or to provide or leverage financing. If that federal funding
5		is not available or not sufficient to meet program objectives,
6		the Commission shall authorize the allocation of up to
7		$20,000,000 to support the thermal energy network pilot
8		projects, to be provided to the Illinois Finance Authority to
9		distribute to projects as a grant or to provide or leverage
10		financing. The Illinois Finance Authority shall submit
11		projects that have already been approved by the Illinois
12		Finance Authority to the Commission for review and approval in
13		a form and manner determined by the Commission. The Commission
14		shall approve projects that it deems to be just, reasonable,
15		and in the public interest. Any allocation of funding shall
16		provide for the Illinois Finance Authority to use a portion of
17		such allocated funds to support its reasonable administrative
18		costs in administering the program under this Section.
19		(b) An electric utility shall be entitled to recover,
20		through tariffed charges approved by the Commission, all of
21		the costs associated with projects authorized for funding by
22		the Commission pursuant to this Section and shall be recovered
23		as part of the utility's costs incurred under Section 45 of the
24		Electric Vehicle Act. If any authorized funds have not been
25		recovered by the utility as of January 1, 2029, the
26		Environmental Protection Agency shall allocate the remaining

SB0025 Enrolled - 646 - LRB104 07069 BAB 17106 b
1		funds to the Illinois Finance Authority as part of its
2		beneficial electrification programs described in Section 45 of
3		the Electric Vehicle Act.
4		(c) As part of any pilot project proposed pursuant to this
5		Section, the Commission is authorized to approve any specific
6		customer rebates and incentives and any project-specific
7		tariffs and rules. The Commission may create a standard
8		proposed rate structure or minimum requirements for a rate
9		structure to be required of all thermal energy network pilot
10		projects. The Commission may approve the proposed rate
11		structure of a thermal energy network pilot project if the
12		projected heating and cooling costs for end users is not
13		greater than the projected heating and cooling costs the end
14		users would have incurred if the end users had not
15		participated in the program. In its approval process, the
16		Commission shall take into account scenarios where pilot
17		projects enhance comfort and safety for customers through
18		expanded access to affordable heating and cooling.
19		(d) Approved thermal energy network pilot projects shall
20		report to the Commission, on a quarterly basis and until
21		completion of the thermal energy network pilot project, the
22		status of each thermal energy network pilot project. The
23		Commission shall post and make publicly available the reports
24		on its website. The reports shall include, but not be limited
25		to:
26		(1) the stage of development of each pilot project;

SB0025 Enrolled - 647 - LRB104 07069 BAB 17106 b
1		(2) the barriers to development;
2		(3) the number of customers served;
3		(4) the costs of the pilot project;
4		(5) the number of jobs retained or created by the
5		pilot project;
6		(6) energy savings and fuel savings from the project
7		and energy consumption by the project; and
8		(7) other information the Commission deems to be in
9		the public interest or considers likely to prove useful or
10		relevant to the rulemaking described in subsection (i).
11		(e) Any entity operating a Commission-approved thermal
12		energy network pilot project shall demonstrate that it has
13		entered into a labor peace agreement with a bona fide labor
14		organization that is actively engaged in representing its
15		employees. The labor peace agreement shall apply to the
16		employees necessary for the ongoing maintenance and operation
17		of the thermal energy network. The existence of a labor peace
18		agreement shall be an ongoing material condition of an
19		entity's authorization to maintain and operate the thermal
20		energy networks.
21		(f) Any contractor or subcontractor that performs work on
22		a thermal energy network pilot project under this Section
23		shall be a responsible bidder, as described in Section 30-22
24		of the Illinois Procurement Code, and shall certify that not
25		less than prevailing wage, as determined under the Prevailing
26		Wage Act, was or will be paid to the employees who are engaged

SB0025 Enrolled - 648 - LRB104 07069 BAB 17106 b
1		in construction activities associated with the pilot thermal
2		energy network system. The contractor or subcontractor shall
3		submit evidence to the Commission that it complied with the
4		requirements of this subsection (f). For any approved thermal
5		energy network pilot project, the contractor or subcontractor
6		shall submit evidence that the contractor or subcontractor has
7		entered into a fully executed project labor agreement for the
8		thermal energy network system prior to the initiation of
9		construction activities.
10		(220 ILCS 5/9-229)
11		Sec. 9-229. Consideration of attorney and expert
12		compensation as an expense and intervenor compensation fund.
13		(a) The Commission shall specifically assess the justness
14		and reasonableness of any amount expended by a public utility
15		to compensate attorneys or technical experts to prepare and
16		litigate a general rate case filing. This issue shall be
17		expressly addressed in the Commission's final order.
18		(b) The State of Illinois shall create a Consumer
19		Intervenor Compensation Fund subject to the following:
20		(1) Provision of compensation for consumer interest
21		representatives Consumer Interest Representatives that
22		intervene in Illinois Commerce Commission proceedings will
23		increase public engagement, encourage additional
24		transparency, expand the information available to the
25		Commission, and improve decision-making.

SB0025 Enrolled - 649 - LRB104 07069 BAB 17106 b
1		(2) As used in this Section, "consumer Consumer
2		interest representative" means:
3		(A) a residential utility customer or group of
4		residential utility customers represented by a
5		not-for-profit group or organization registered with
6		the Illinois Attorney General under the Solicitation
7		for Charity Act;
8		(B) representatives of not-for-profit groups or
9		organizations whose membership is limited to
10		residential utility customers; or
11		(C) representatives of not-for-profit groups or
12		organizations whose membership includes Illinois
13		residents and that address the community, economic,
14		environmental, or social welfare of Illinois
15		residents, except government agencies or intervenors
16		specifically authorized by Illinois law to participate
17		in Commission proceedings on behalf of Illinois
18		consumers.
19		(3) A consumer interest representative is eligible to
20		receive compensation from the Consumer Intervenor
21		Compensation Fund consumer intervenor compensation fund if
22		its participation included lay or expert testimony or
23		legal briefing and argument concerning the expenses,
24		investments, rate design, rate impact, development of an
25		integrated resource plan pursuant to Section 16-201 and
26		any related proceedings, or other matters affecting the

SB0025 Enrolled - 650 - LRB104 07069 BAB 17106 b
1		pricing, rates, costs or other charges associated with
2		utility service and , the Commission does not find the
3		participation to be immaterial adopts a material
4		recommendation related to a significant issue in the
5		docket, and participation caused a significant financial
6		hardship to the participant; however, no consumer interest
7		representative shall be eligible to receive an award
8		pursuant to this Section if the consumer interest
9		representative receives any compensation, funding, or
10		donations, directly or indirectly, from parties that have
11		a financial interest in the outcome of the proceeding.
12		Funding from residential ratepayers shall not be
13		considered funding from a party with a financial interest
14		unless determined to be by the Commission. The Commission
15		shall determine participation by the consumer interest
16		representative to be material if recommendations made by
17		the consumer interest representative are:
18		(A) relevant to issues in the proceeding on which
19		the Commission makes a finding;
20		(B) supported by facts, such as studies, methods,
21		or calculations, or by legal or policy analysis; and
22		(C) offered by the consumer interest
23		representative into evidence in the record of that
24		proceeding, or for legal or policy analysis, are filed
25		in the docket of that proceeding, through briefing,
26		motion, or other method.

SB0025 Enrolled - 651 - LRB104 07069 BAB 17106 b
1		(4) Within 30 days after September 15, 2021 (the
2		effective date of Public Act 102-662), each utility that
3		files a request for an increase in rates under Article IX
4		or Article XVI shall deposit an amount equal to one half of
5		the rate case attorney and expert expense allowed by the
6		Commission, but not to exceed $500,000, into the fund
7		within 35 days of the date of the Commission's final Order
8		in the rate case or 20 days after the denial of rehearing
9		under Section 10-113 of this Act, whichever is later. The
10		Consumer Intervenor Compensation Fund shall be used to
11		provide payment to consumer interest representatives as
12		described in this Section.
13		(5) An electric public utility with 3,000,000 or more
14		retail customers shall contribute $450,000 to the Consumer
15		Intervenor Compensation Fund within 60 days after
16		September 15, 2021 (the effective date of Public Act
17		102-662). A combined electric and gas public utility
18		serving fewer than 3,000,000 but more than 500,000 retail
19		customers shall contribute $225,000 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 gas public utility with 1,500,000 or more
23		retail customers that is not a combined electric and gas
24		public utility shall contribute $225,000 to the Consumer
25		Intervenor Compensation Fund within 60 days after
26		September 15, 2021 (the effective date of Public Act

SB0025 Enrolled - 652 - LRB104 07069 BAB 17106 b
1		102-662). A gas public utility with fewer than 1,500,000
2		retail customers but more than 300,000 retail customers
3		that is not a combined electric and gas public utility
4		shall contribute $80,000 to the Consumer Intervenor
5		Compensation Fund within 60 days after September 15, 2021
6		(the effective date of Public Act 102-662). A gas public
7		utility with fewer than 300,000 retail customers that is
8		not a combined electric and gas public utility shall
9		contribute $20,000 to the Consumer Intervenor Compensation
10		Fund within 60 days after September 15, 2021 (the
11		effective date of Public Act 102-662). A combined electric
12		and gas public utility serving fewer than 500,000 retail
13		customers shall contribute $20,000 to the Consumer
14		Intervenor Compensation Fund within 60 days after
15		September 15, 2021 (the effective date of Public Act
16		102-662). A water or sewer public utility serving more
17		than 100,000 retail customers shall contribute $80,000,
18		and a water or sewer public utility serving fewer than
19		100,000 but more than 10,000 retail customers shall
20		contribute $20,000.
21		(6)(A) Prior to the entry of a final order Final Order
22		in a docketed case, the Commission Administrator shall
23		provide a payment to a consumer interest representative
24		that demonstrates through a verified application for
25		funding that the consumer interest representative's
26		participation or intervention without an award of fees or

SB0025 Enrolled - 653 - LRB104 07069 BAB 17106 b
1		costs imposes a significant financial cost for the
2		consumer interest representative hardship based on a
3		schedule to be developed by the Commission. The
4		Administrator may require verification of costs expected
5		to be incurred, including statements of expected hours
6		spent, as a condition to paying the consumer interest
7		representative prior to the entry of a final order Final
8		Order in a docketed case. The upfront payment prior to the
9		entry of a final order in the relevant docketed case shall
10		be subject to the reconciliation process described in
11		subparagraph (C) of this paragraph. For purposes of
12		upfront payments provided for under this subparagraph, and
13		provided the testimony or legal argument was offered into
14		evidence or filed in the docket, a decision by the
15		Commission prior to entry of a final order that a consumer
16		interest representative's evidence or legal argument is
17		relevant to issues in the proceeding under subparagraph
18		(A) of paragraph (3) shall not be subject to
19		reconsideration. Any compensation awarded shall be subject
20		to review and reconciliation under subparagraph (C) of
21		this paragraph. Payments made after the issuance of a
22		final order in the relevant docketed case do not require
23		the reconciliation.
24		(B) If the Commission does not find the participation
25		to be immaterial adopts a material recommendation related
26		to a significant issue in the docket and participation

SB0025 Enrolled - 654 - LRB104 07069 BAB 17106 b
1		caused a financial hardship to the participant, then the
2		consumer interest representative shall be allowed payment
3		for some or all of the consumer interest representative's
4		reasonable attorney's or advocate's fees, reasonable
5		expert witness fees, and other reasonable costs of
6		preparation for and participation in a hearing or
7		proceeding. Expenses related to travel or meals shall not
8		be compensable. Expenses incurred by participation in
9		workshops or other informal processes outside a docketed
10		proceeding shall not be compensable. Attorneys and expert
11		witnesses who represent or testify for more than one party
12		in the same docketed proceeding and perform essentially
13		the same work on behalf of the parties shall not be
14		compensated more than once for those same services
15		rendered in that proceeding.
16		(C) The consumer interest representative shall submit
17		an itemized request for compensation to the Consumer
18		Intervenor Compensation Fund, including the advocate's or
19		attorney's reasonable fee rate, the number of hours
20		expended, reasonable expert and expert witness fees, and
21		other reasonable costs for the preparation for and
22		participation in the hearing and briefing within 30 days
23		after of the Commission's final order or the Commission's
24		after denial or decision on rehearing, if any, whichever
25		is later. If compensation is provided prior to the entry
26		of a final order in a docketed case, such compensation

SB0025 Enrolled - 655 - LRB104 07069 BAB 17106 b
1		shall be adjusted following the final order to reconcile
2		the difference between actual eligible expenses incurred
3		and the amount of compensation provided prior to the entry
4		of the final order. The reconciliation adjustment shall
5		ensure that the total compensation awarded to the
6		applicant is no more and no less than the actual eligible
7		expenses incurred. Payments made after the issuance of a
8		final order in the relevant docketed case do not require
9		the reconciliation.
10		(7) Administration of the Fund.
11		(A) The Consumer Intervenor Compensation Fund is
12		created as a special fund in the State treasury. All
13		disbursements from the Consumer Intervenor Compensation
14		Fund shall be made only upon warrants of the Comptroller
15		drawn upon the Treasurer as custodian of the Fund upon
16		vouchers signed by the Executive Director of the
17		Commission or by the person or persons designated by the
18		Director for that purpose. The Comptroller is authorized
19		to draw the warrant upon vouchers so signed. The Treasurer
20		shall accept all warrants so signed and shall be released
21		from liability for all payments made on those warrants.
22		The Consumer Intervenor Compensation Fund shall be
23		administered by an Administrator that is a person or
24		entity that is independent of the Commission. The
25		administrator will be responsible for the prudent
26		management of the Consumer Intervenor Compensation Fund

SB0025 Enrolled - 656 - LRB104 07069 BAB 17106 b
1		and for recommendations for the award of consumer
2		intervenor compensation from the Consumer Intervenor
3		Compensation Fund. The Commission shall issue a request
4		for qualifications for a third-party program administrator
5		to administer the Consumer Intervenor Compensation Fund.
6		The third-party administrator shall be chosen through a
7		competitive bid process based on selection criteria and
8		requirements developed by the Commission. The Illinois
9		Procurement Code does not apply to the hiring or payment
10		of the Administrator. All Administrator costs may be paid
11		for using monies from the Consumer Intervenor Compensation
12		Fund, but the Program Administrator shall strive to
13		minimize costs in the implementation of the program.
14		(B) The computation of compensation awarded from the
15		fund shall take into consideration the market rates paid
16		to persons of comparable training and experience who offer
17		similar services, but may not exceed the comparable market
18		rate for services paid by the public utility as part of its
19		rate case expense.
20		(C)(1) Recommendations on the award of compensation by
21		the administrator shall include consideration of whether
22		the participation was material Commission adopted a
23		material recommendation related to a significant issue in
24		the docket and whether participation caused a financial
25		hardship to the participant and the payment of
26		compensation is fair, just and reasonable.

SB0025 Enrolled - 657 - LRB104 07069 BAB 17106 b
1		(2) Recommendations on the award of compensation by
2		the administrator shall be submitted to the Commission for
3		approval within 30 days after when the application for
4		funding is submitted to the administrator. Unless the
5		Commission initiates an investigation within 60 45 days
6		after an application for funding is submitted to the
7		administrator, the Commission shall within 90 days after
8		the application is submitted to the administrator, or as
9		soon as practicable thereafter, award funding to the
10		applicant. Notice of the administrator's award
11		recommendation the notice to the Commission, the award of
12		compensation shall be allowed 45 days after notice to the
13		Commission. Such notice shall be given by filing with the
14		Commission on the Commission's e-docket system, and
15		keeping open for public inspection the award for
16		compensation proposed by the Administrator. The Commission
17		shall have power, and it is hereby given authority, either
18		upon complaint or upon its own initiative without
19		complaint, at once, and if it so orders, without answer or
20		other formal pleadings, but upon reasonable notice, to
21		enter upon a hearing concerning the propriety of the
22		award.
23		(c) The Commission may adopt rules to implement this
24		Section.
25		(Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)

SB0025 Enrolled - 658 - LRB104 07069 BAB 17106 b
1		(220 ILCS 5/16-105.17)
2		Sec. 16-105.17. Multi-Year Integrated Grid Plan.
3		(a) The General Assembly finds that ensuring alignment of
4		regulated utility operations, expenditures, and investments
5		with public benefit goals, including safety, reliability,
6		resiliency, affordability, equity, emissions reductions, and
7		expansion of clean distributed energy resources, is critical
8		to maximizing the benefits of the interconnected utility grid
9		and cost-effective utility expenditures on the grid. It is the
10		policy of the State to promote inclusive, comprehensive,
11		transparent, cost-effective distribution system planning and
12		disclosures processes that minimize long-term costs for
13		Illinois customers and support the achievement of State
14		renewable energy development and other clean energy, public
15		health, and environmental policy goals. Utility distribution
16		system expenditures, programs, investments, and policies must
17		be evaluated in coordination with these goals. In particular,
18		the General Assembly finds that:
19		(1) Investment in infrastructure to support and enable
20		existing and new distributed energy resources creates
21		significant economic development, environmental, and
22		public health benefits in the State.
23		(2) Illinois' electricity distribution system must
24		cost-effectively integrate renewable energy resources,
25		including utility-scale renewable energy resources,
26		community renewable generation, and distributed renewable

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1		energy resources, support beneficial electrification,
2		including electric vehicle use and adoption, promote
3		opportunities for third-party investment in
4		nontraditional, grid-related technologies and resources
5		such as batteries, solar photovoltaic panels, and smart
6		thermostats, reduce energy usage generally and especially
7		during times of greatest reliance on fossil fuels, and
8		enhance customer engagement opportunities.
9		(3) Inclusive distribution system planning is an
10		essential tool for the Commission, public utilities, and
11		stakeholders to effectively coordinate environmental,
12		consumer, reliability, and equity goals at fair and
13		reasonable costs, and for ensuring transparent utility
14		accountability for meeting those goals.
15		(4) Any planning process should advance Illinois
16		energy policy goals while ensuring utility investments are
17		cost-effective. Such a process should maximize the sharing
18		of information, minimize overlap with existing filing
19		requirements to ensure robust stakeholder participation,
20		and recognize the responsibility of the utility to manage
21		the grid in a safe, reliable manner.
22		(5) The General Assembly is concerned that, in the
23		absence of a transparent, meaningful distribution system
24		planning process, utility investments may not always serve
25		customers' best interests, appropriately promote the
26		expansion of clean distributed energy resources, and

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1		advance equity and environmental justice.
2		(6) The General Assembly is also encouraged by the
3		opportunities presented by nontraditional solutions to
4		utility, customer, and grid needs that may be more
5		efficient and cost-effective, and less environmentally
6		harmful than traditional solutions. Nontraditional
7		solutions include distributed energy resources owned or
8		implemented by customers and independent third parties,
9		controllable load, beneficial electrification, or rate
10		design that encourages efficient energy use.
11		(7) The General Assembly finds that Illinois
12		utilities' current processes for planning their
13		distribution system should be made more accessible and
14		transparent to individuals and communities, and that more
15		inclusive and accessible distribution system planning
16		processes would be in the interests of all Illinois
17		residents.
18		(8) The General Assembly finds it would be beneficial
19		to require utilities to demonstrate how their spending
20		promotes identified State clean energy goals, such as
21		integrating renewable energy, empowering customers to make
22		informed choices, supporting electric vehicles, beneficial
23		electrification, and energy storage, achieving equity
24		goals, enhancing resilience, and maintaining reliability.
25		The General Assembly therefore directs the utilities to
26		implement distribution system planning as described in this

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1		Section in order to accelerate progress on Illinois clean
2		energy and environmental goals and hold electric utilities
3		publicly accountable for their performance.
4		(b) Unless otherwise specified, the terms used in this
5		Section shall have the same meanings as defined in Sections
6		16-102 and 16-107.6. As used in this Section:
7		"Demand response" means measures that decrease peak
8		electricity demand or shift demand from peak to off-peak
9		periods.
10		"Distributed energy resources" or "DER" means a wide range
11		of technologies that are connected to the grid, including
12		those that are located on the customer side of the customer's
13		electric meter and can provide value to the distribution
14		system, including, but not limited to, distributed generation,
15		energy storage, electric vehicles, and demand response
16		technologies.
17		"Environmental justice communities" means the definition
18		of that term based on existing methodologies and findings,
19		used and as may be updated by the Illinois Power Agency and its
20		Program Administrator in the Illinois Solar for All Program.
21		(c) This Section applies to electric utilities serving
22		more than 500,000 retail customers in the State.
23		(d) The Multi-Year Integrated Grid Plan ("the Plan") shall
24		be designed to:
25		(1) ensure coordination of the State's renewable
26		energy goals, climate and environmental goals with the

SB0025 Enrolled - 662 - LRB104 07069 BAB 17106 b
1		utility's distribution system investments, and programs
2		and policies over a 5-year planning horizon to maximize
3		the benefits of each while ensuring utility expenditures
4		are cost-effective;
5		(2) optimize utilization of electricity grid assets
6		and resources to minimize total system costs;
7		(3) support efforts to bring the benefits of grid
8		modernization and clean energy, including, but not limited
9		to, deployment of distributed energy resources, to all
10		retail customers, and support efforts to bring at least
11		40% of the benefits of those benefits to Equity Investment
12		Eligible Communities. Nothing in this paragraph is meant
13		to require a specific amount of spending in a particular
14		geographic area;
15		(4) enable greater customer engagement, empowerment,
16		and options for energy services;
17		(5) reduce grid congestion, minimize the time and
18		expense associated with interconnection, and increase the
19		capacity of the distribution grid to host increasing
20		levels of distributed energy resources, to facilitate
21		availability and development of distributed energy
22		resources, particularly in locations that enhance consumer
23		and environmental benefits;
24		(6) ensure opportunities for robust public
25		participation through open, transparent planning
26		processes.

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1		(7) provide for the analysis of the cost-effectiveness
2		of proposed system investments, which takes into account
3		environmental costs and benefits;
4		(8) to the maximum extent practicable, achieve or
5		support the achievement of Illinois environmental goals,
6		including those described in Section 9.10 of the
7		Environmental Protection Act and Section 1-75 of the
8		Illinois Power Agency Act, and emissions reductions
9		required to improve the health, safety, and prosperity of
10		all Illinois residents;
11		(9) support existing Illinois policy goals promoting
12		the long-term growth of energy efficiency, demand
13		response, and investments in renewable energy resources;
14		(10) provide sufficient public information to the
15		Commission, stakeholders, and market participants in order
16		to enable nonemitting customer-owned or third-party
17		distributed energy resources, acting individually or in
18		aggregate, to seamlessly and easily connect to the grid,
19		provide grid benefits, support grid services, and achieve
20		environmental outcomes, without necessarily requiring
21		utility ownership or controlling interest over those
22		resources, and enable those resources to act as
23		alternatives to utility capital investments; and
24		(11) provide delivery services at rates that are
25		affordable to all customers, including low-income
26		customers.

SB0025 Enrolled - 664 - LRB104 07069 BAB 17106 b
1		(e) Plan Development Stakeholder Process.
2		(1) To promote the transparency of utility
3		distributions system planned investments and the planning
4		process for those investments, the Commission shall
5		convene a workshop process, over a period of no less than 5
6		months, for each such utility for the purpose of
7		establishing an open, inclusive, and cooperative forum
8		regarding such investments. The workshops shall be
9		facilitated by an independent, third-party facilitator
10		selected by the Commission. Data and projections provided
11		through the workshop process shall be designed to provide
12		participants with information about the electric utility's
13		(i) historic distribution system investments for at least
14		the 5 years prior to the year in which the workshop is held
15		and (ii) planned investments for the 5-year period
16		following the year in which the workshop is held. The
17		workshop process shall recognize that estimates for later
18		years will be less reliable and indicative of future
19		conduct than estimates for earlier years and that the
20		electric utility is subject to financial and system
21		planning processes. No later than January 1, 2022, the
22		facilitator shall initiate a series of workshops for each
23		electric utility subject to this Section. The series of
24		workshops shall include no fewer than 6 workshops and
25		shall conclude no later than June 1, 2022.
26		(2) The workshops shall be designed to achieve the

SB0025 Enrolled - 665 - LRB104 07069 BAB 17106 b
1		following objectives:
2		(A) review utilities' planned capital investments
3		and supporting data;
4		(B) review how utilities plan to invest in their
5		distribution system in order to meet the system's
6		projected needs;
7		(C) review system and locational data on
8		reliability, resiliency, DER, and service quality
9		provided by the utilities;
10		(D) solicit and consider input from diverse
11		stakeholders, including representatives from
12		environmental justice communities, geographically
13		diverse communities, low-income representatives,
14		consumer representatives, environmental
15		representatives, organized labor representatives,
16		third-party technology providers, and utilities;
17		(E) consider proposals from utilities and
18		stakeholders on programs and policies necessary to
19		achieve the objectives in subsection (d) of this
20		Section;
21		(F) consider proposals applicable to each
22		component of the utilities' Multi-Year Integrated Grid
23		Plan filings under paragraph (2) of subsection (f) of
24		this Section;
25		(G) educate and equip interested stakeholders so
26		that they can effectively and efficiently provide

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1		feedback and input to the electric utility; and
2		(H) review planned capital investment to ensure
3		that delivery services are provided at rates that are
4		affordable to all customers, including low-income
5		customers.
6		(3) To the extent any of the information in
7		subparagraphs (A) through (H) of paragraph (2) of this
8		subsection is designated as confidential and proprietary
9		under the Commission's rules, the proponent of the
10		designation shall have the burden of making the requisite
11		showing under the Commission's rules. For data that is
12		determined to be confidential or that includes personally
13		identifiable information, the Commission may develop
14		procedures and processes to enable data sharing with
15		parties and stakeholders while ensuring the
16		confidentiality of the information.
17		(4) Workshops should be organized and facilitated in a
18		manner that encourages representation from diverse
19		stakeholders, ensuring equitable opportunities for
20		participation, without requiring formal intervention or
21		representation by an attorney. Workshops should be held
22		during both day and evening hours, in a variety of
23		locations within each electric utility's service
24		territory, and should allow remote participation.
25		(5) It is a goal of the State that this workshop
26		process will provide a forum for interested stakeholders

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1		to effectively and efficiently provide feedback and input
2		to the electric utility. It is also a goal of the State
3		that stakeholder participation in this process will
4		prepare stakeholders to more capably participate in
5		Multi-Year Rate Plan proceedings conducted pursuant to
6		Section 16-108.18 of this Act, if they so elect. As part of
7		the workshop process, the electric utility shall submit to
8		the Commission the electric utility's capital investments
9		proposal, and supporting data described in subparagraphs
10		(A) through (C) of paragraph (2) of this subsection (e)
11		before the start of workshops to allow interested
12		stakeholders to reasonably review data before attending
13		workshops. The Commission shall make public the utility
14		capital investments proposal by posting it on the
15		Commission's website and set the location and time of any
16		workshop to be held as part of the workshop process, and
17		establish a data request process, consistent with the
18		Commission's rules, that affords workshop participants
19		opportunities to submit data requests to the utility, and
20		receive responses in accordance with the utility's
21		obligations under the law, prior to the workshop,
22		regarding the information described in this paragraph (5).
23		Upon the written request of a workshop participant, the
24		utility shall also present at a given workshop at least
25		one appropriate company representative who can address the
26		specific written questions or written categories of

SB0025 Enrolled - 668 - LRB104 07069 BAB 17106 b
1		questions identified in advance by the workshop
2		participant regarding issues related to the utility's
3		Multi-Year Integrated Grid Plan. To facilitate public
4		feedback, the administrator facilitating the workshops
5		shall, throughout the workshop process, develop questions
6		for stakeholder input on topics being considered. This may
7		include, but is not limited to: design of the workshop
8		process, locational data and information provided by
9		utilities, alignment of plans, programs, investments and
10		objectives, and other topics as deemed appropriate by the
11		Commission facilitation staff. Stakeholder feedback shall
12		not be limited to these questions. The information
13		provided as part of the workshop process pursuant to this
14		subsection (e) is intended to be informational and to
15		provide a preliminary view of costs and investments, which
16		may change. Accordingly, the information provided pursuant
17		to this subsection (e) shall not be binding on the utility
18		and shall not be the sole basis for a finding in any
19		Commission proceeding of imprudence, unreasonableness, or
20		lack of use or usefulness of any individual or aggregate
21		level of utility plant or other investment or expenditure
22		addressed; however, information contained in the plan may
23		be used in a proceeding before the Commission, with weight
24		of such evidence to be determined by the Commission.
25		(6) Workshops shall not be considered settlement
26		negotiations, compromise negotiations, or offers to

SB0025 Enrolled - 669 - LRB104 07069 BAB 17106 b
1		compromise for the purposes of Illinois Rule of Evidence
2		408. All materials shared as a part of the workshop
3		process, and that are not determined to be confidential as
4		described in paragraph (3) of this subsection (e), shall
5		be made publicly available on a website made available by
6		the Commission.
7		(7) On conclusion of the workshops, the Commission
8		shall open a comment period that allows interested and
9		diverse stakeholders to submit comments and
10		recommendations regarding the utility's Multi-Year
11		Integrated Grid Plan filing. Based on the workshop process
12		and stakeholder comments and recommendations offered
13		verbally or in writing during the workshops and in writing
14		during the comment period following the workshops, the
15		independent third-party facilitator shall prepare a
16		report, to be submitted to the Commission no later than
17		July 1, 2022, describing the stakeholders, discussions,
18		proposals, and areas of consensus and disagreement from
19		the workshop process, and making recommendations to the
20		Commission regarding the utility's Multi-Year Integrated
21		Grid Plan. Interested stakeholders shall have an
22		opportunity to provide comment on the independent
23		third-party facilitator report.
24		(8) Based on discussions in the workshops, the
25		independent third-party facilitator report, and
26		stakeholder comments and recommendations made during and

SB0025 Enrolled - 670 - LRB104 07069 BAB 17106 b
1		following the workshop process, the Commission shall issue
2		initiating orders no later than August 1, 2022, requiring
3		the electric utilities subject to this Section to file the
4		first Multi-Year Integrated Grid Plan no later than
5		January 20, 2023. The initiating orders shall specify the
6		requirements applicable to the utilities' Multi-Year
7		Integrated Grid Plans, which shall supplement and not
8		replace those requirements described in subsection (f) of
9		this Section.
10		(f) Multi-Year Integrated Grid Plan.
11		(1) Pursuant to this subsection (f) and the initiating
12		orders of the Commission, each electric utility subject to
13		this Section shall, no later than January 20, 2023, submit
14		its first Multi-Year Integrated Grid Plan. No later than
15		January 20, 2026, and every 4 years thereafter, the
16		utility shall submit its subsequent Plan. Each Plan shall:
17		(A) incorporate requirements established by the
18		Commission in its initiating order; and
19		(B) propose distribution system investment
20		programs, policies, and plans designed to optimize
21		achievement of the objectives set forth in subsection
22		(d) of this Section and achieve the metrics approved
23		by the Commission pursuant to Section 16-108.18 of
24		this Act.
25		To the extent practicable and reasonable, all
26		programs, policies, and initiatives proposed by the

SB0025 Enrolled - 671 - LRB104 07069 BAB 17106 b
1		utility in its plan should be informed by stakeholder
2		input received during the workshop process pursuant to
3		subsection (e) of this Section. Where specific stakeholder
4		input has not been incorporated in proposed programs,
5		policies, and plans, the electric utility shall provide an
6		explanation as to why that input was not incorporated.
7		(2) In order to ensure electric utilities' ability to
8		meet the goals and objectives set forth in this Section,
9		the Multi-Year Integrated Grid Plans must include, at
10		minimum, the following information:
11		(A) A description of the utility's distribution
12		system planning process, including:
13		(i) the overview of the process, including
14		frequency and duration of the process, roles, and
15		responsibilities of utility personnel and
16		departments involved;
17		(ii) a summary of the meetings with
18		stakeholders conducted prior to filing of the plan
19		with the Commission.
20		(iii) the description of any coordination of
21		the processes with any other planning process
22		internal or external to the utility, including
23		those required by a regional transmission
24		operator.
25		(B) A detailed description of the current
26		operating conditions for the distribution system

SB0025 Enrolled - 672 - LRB104 07069 BAB 17106 b
1		separately presented for each of the utility's
2		operating areas, where possible, including a detailed
3		description, with supporting data, of system
4		conditions, including baseline data regarding the
5		utility's distribution system from the utility's
6		annual report to the Commission, total distribution
7		system substation capacity in kVa, total miles of
8		primary overhead distribution wire, and total miles of
9		primary underground distribution cable, distributed
10		energy resource deployment by type, size, customer
11		class, and geographic dispersion as to those DERs that
12		have completed the interconnection process, the most
13		current distribution line loss study, current and
14		expected System Average Interruption Frequency Index
15		and Customer Average Interruption Duration Index data
16		for the system, identification of the system model
17		software currently used and planned software
18		deployments, and other data needs as requested by the
19		Commission or as determined through Commission rules.
20		The description shall also include the utility's most
21		recent system load and peak demand forecast for at
22		least the next 5 years, and up to 10 years if
23		available, a discussion of how the forecast was
24		prepared and how distributed energy resources and
25		energy efficiency were factored into the forecast, and
26		identification of the forecasting software currently

SB0025 Enrolled - 673 - LRB104 07069 BAB 17106 b
1		used and planned software deployments.
2		(C) Financial Data.
3		(i) For each of the preceding 5 years, the
4		utility's distribution system investments by the
5		investment categories tracked by the utility,
6		including, but not limited to, new business,
7		facility relocation, capacity expansion, system
8		performance, preventive maintenance, corrective
9		maintenance, the total amount of investments
10		associated with the integration of DERs, the total
11		amount of charges to DER developers and retail
12		customers for interconnection of DERs to the
13		distribution system, and a list of each major
14		investment category the utility used to maintain
15		its routine standing operational activities and
16		the associated plant in service amount for each
17		category in which the plant in service amount is
18		at least $2,000,000;
19		(ii) For each of the preceding 5 years, data
20		on and a discussion of the utility's distribution
21		system operation and maintenance expenses;
22		(iii) A 5-year long-range forecast of
23		distribution system capital investments and
24		operational and maintenance expenses, including a
25		discussion of any projections for expenses for the
26		categories listed in subparagraph (i) of this item

SB0025 Enrolled - 674 - LRB104 07069 BAB 17106 b
1		(C).
2		(D) System data on DERs on the utility's
3		distribution system, including the total number and
4		nameplate capacity of DERs that completed
5		interconnection in the prior year, current DER
6		deployment by type, size, and geographic dispersion,
7		to the extent that granular geographic information
8		does not disclose personally identifiable information,
9		and other data as requested by the Commission or
10		determined by Commission rules.
11		(E) Hosting Capacity and Interconnection
12		Requirements.
13		(i) The utility shall make available on its
14		website the hosting capacity analysis results that
15		shall include mapping and GIS capability, as well
16		as any other requirements requested by the
17		Commission or determined through Commission rules.
18		The plan shall identify where the hosting capacity
19		analysis results shall be made publicly available.
20		This shall also include an assessment of the
21		impact of utility investments over the next 5
22		years on hosting capacity and a narrative
23		discussion of how the hosting capacity analysis
24		advances customer-sited distributed energy
25		resources, including electric vehicles, energy
26		storage systems, and photovoltaic resources, and

SB0025 Enrolled - 675 - LRB104 07069 BAB 17106 b
1		how the identification of interconnection points
2		on the distribution system will support the
3		continued development of distributed energy
4		resources.
5		(ii) Discussion of the utility's
6		interconnection requirements and how they comply
7		with the Commission's applicable regulations.
8		(F) Identification and discussion of the scenarios
9		considered in the development of the utility's
10		Multi-Year Integrated Grid Plan, including DER
11		scenarios, and discussion of base-case and alternative
12		scenarios, how the scenarios were developed and
13		selected, and how the scenarios include a reasonable
14		mix of DERs scenarios, types, and geographic
15		dispersion. Scenarios shall at least consider the
16		5-year forecast horizon of the Multi-Year Integrated
17		Grid Plan, but may also consider longer-term scenarios
18		where data is available. The plan shall also include
19		requirements requested by the Commission or determined
20		through Commission rules.
21		(G) An evaluation of the short-term and long-run
22		benefits and costs of distributed energy resources
23		located on the distribution system, including, but not
24		limited to, the locational, temporal, and
25		performance-based benefits and costs of distributed
26		energy resources. The utility shall use the results of

SB0025 Enrolled - 676 - LRB104 07069 BAB 17106 b
1		this evaluation to inform its analysis of Solution
2		Sourcing Opportunities, including nonwires
3		alternatives, under subparagraph (K) of paragraph (2)
4		subsection (f) of this Section. The Commission may use
5		the data produced through this evaluation to, among
6		other use-cases, inform the Commission's investigation
7		and establishment of tariffs and compensation for
8		distributed energy resources interconnecting to the
9		utility's distribution system, including rebates
10		provided by the electric utility pursuant to Section
11		16-107.6 of this Act.
12		(H) Long-term Distribution System Investment Plan.
13		(i) The utility's planned distribution capital
14		investments for the period covered by the planning
15		process required by this Section, by the
16		investment categories used by the utility, and
17		with discussion of any individual planned projects
18		with a planned total investment gross amount of
19		$3,000,000 or more and of the alternatives
20		considered by the utility to such individual
21		projects including any non-traditional
22		alternatives and DER alternatives, and supporting
23		data. This shall provide sufficiently detailed
24		explanations of how the planned investments shall
25		support the goals in subsection (d) of this
26		Section.

SB0025 Enrolled - 677 - LRB104 07069 BAB 17106 b
1		(ii) Discussion of how the utility's capital
2		investments plan is consistent with Commission
3		orders regarding the procurement of renewable
4		resources as discussed in Section 16-111.5 of this
5		Act, energy efficiency plans as discussed in
6		Section 8-103B, distributed generation rebates as
7		discussed in Section 16-107.6, and any other
8		Commission order affecting the goals described in
9		subsection (d) of this Section.
10		(iii) A plan for achieving the applicable
11		metrics that were approved by the Commission for
12		the utility pursuant to subsection (e) of Section
13		16-108.18 of this Act.
14		(iv) A narrative discussion of the utility's
15		vision for the distribution system over the next 5
16		years.
17		(v) Any additional information requested by
18		the Commission or determined through Commission
19		rules.
20		(I) A detailed description of historic
21		distribution system operations and maintenance
22		expenditures for the preceding 5 years and of planned
23		or projected operations and maintenance expenditures
24		for the period covered by the planning process
25		required by this Section, as well as the data,
26		reasoning and explanation supporting planned or

SB0025 Enrolled - 678 - LRB104 07069 BAB 17106 b
1		projected expenditures. Any additional information
2		requested by the Commission or determined through
3		Commission rules.
4		(J) A detailed plan for achieving the applicable
5		metrics that were approved by the Commission for the
6		utility pursuant to subsection (e) of Section
7		16-108.18 of this Act, including, but not limited to,
8		the following:
9		(i) A description of, exclusive of low-income
10		rate relief programs and other income-qualified
11		programs, how the utility is supporting efforts to
12		bring 40% of benefits from programs, policies, and
13		initiatives proposed in their Multi-Year
14		Integrated Grid Plan to ratepayers in low-income
15		and environmental justice communities. This shall
16		also include any information requested by the
17		Commission or determined through Commission rules.
18		Nothing in this subparagraph is meant to require a
19		specific amount of spending in a particular
20		geographic area.
21		(ii) A detailed analysis of current and
22		projected flexible resources, including resource
23		type, size (in MW and MWh), location and
24		environmental impact, as well as anticipated needs
25		that can be met using flexible resources, to meet
26		the goals described in subsection (d) of this

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1		Section, to meet the applicable metrics that were
2		approved by the Commission for the utility
3		pursuant to subsection (e) of Section 16-108.18 of
4		this Act, and any other Commission order affecting
5		the goals described in subsection (d) of this
6		Section.
7		(iii) Any additional information requested by
8		the Commission or determined through Commission
9		rules.
10		(K) Identification of potential cost-effective
11		solutions from nontraditional and third-party owned
12		investments that could meet anticipated grid needs,
13		including, but not limited to, distributed energy
14		resources procurements, tariffs or contracts,
15		programmatic solutions, rate design options,
16		technologies or programs that facilitate load
17		flexibility, nonwires alternatives, and other
18		solutions that are intended to meet the objectives
19		described at subsection (d). It is the policy of this
20		State that cost-effective third-party or
21		customer-owned distributed energy resources create
22		robust competition and customer choice and shall be
23		considered as appropriate. The Commission shall
24		establish rules determining data or methods for
25		Solution Sourcing Opportunities.
26		(L) A detailed description of the utility's

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1		interoperability plan, which must describe the manner
2		in which the electric utility's current and planned
3		distribution system investments will work together and
4		exchange information and data, the extent to which the
5		utility is implementing open standards and interfaces
6		with third-party distributed energy resource owners
7		and aggregators, and the utility's plan for
8		interoperability testing and certification.
9		(M) For plans that include a time period that is
10		after January 1, 2029, a description of efforts to
11		support transportation electrification through the
12		following:
13		(i) make-ready investments and other programs
14		to facilitate the rapid deployment of charging
15		equipment throughout this State, especially
16		deployment that targets medium-duty and heavy-duty
17		vehicle electrification and multi-unit buildings;
18		(ii) the development and implementation of (1)
19		time-of-use rates and their benefit for electric
20		vehicle users and for all customers, (2) optimized
21		charging programs to achieve identified savings,
22		and (3) new contracts and compensation for
23		services in the optimized charging programs,
24		through signals that allow electric vehicle
25		charging to respond to local system conditions,
26		manage critical peak periods, serve as a demand

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1		response or peak resource, and maximize renewable
2		energy use and integration into the grid; and
3		(iii) commercial tariffs utilizing
4		alternatives to traditional demand-based rate
5		structures that facilitate charging for
6		light-duty, heavy-duty, and fleet electric
7		vehicles.
8		For items (i) through (iii), the utility shall
9		demonstrate methods of minimizing ratepayer
10		impacts and exempting or minimizing, to the extent
11		possible, low-income ratepayers from the costs
12		associated with facilitating the expansion of
13		electric vehicle charging. Investments, programs,
14		and activities proposed to meet the obligations of
15		this subparagraph (M) shall be evaluated and
16		approved by the Commission using the same
17		standards of cost-effectiveness, as described in
18		paragraph (7) of subsection (d), and not be
19		subject to evaluation standards applied to other
20		investments, programs, and activities, such as
21		energy efficiency programs.
22		(3) To the extent any information in utilities'
23		Multi-Year Integrated Grid Plans is designated as
24		confidential and proprietary under the Commission's rules,
25		the proponent of the designation shall have the burden of
26		making the requisite showing under the Commission's rules.

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

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1		(4) It is the policy of this State that holistic
2		consideration of all related investments, planning
3		processes, tariffs, rate design options, programs, and
4		other utility policies and plans shall be required. To
5		that end, the Commission shall consider, comprehensively,
6		the impact of all related plans, tariffs, programs, and
7		policies on the Plan and on each other, including:
8		(A) time-of-use pricing program pursuant to
9		Section 16-107.7 of this Act, hourly pricing program
10		pursuant to Section 16-107 of this Act, and any other
11		time-variant or dynamic pricing program;
12		(B) distributed generation rebate pursuant to
13		Section 16-107.6 of this Act;
14		(C) net electricity metering, pursuant to Section
15		16-107.5 of this Act;
16		(D) energy efficiency programs pursuant to Section
17		8-103B of this Act;
18		(E) beneficial electrification programs pursuant
19		to Section 16-107.8 of this Act;
20		(F) Equitable Energy Upgrade Program pursuant to
21		Section 16-111.10 of this Act;
22		(G) renewable energy programs and procurements set
23		forth in the Illinois Power Agency Act, including, but
24		not limited to, those set forth in the long-term
25		renewable resources procurement plan developed
26		pursuant to Section 1-20 of that Act; and

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1		(H) other plans, programs, and policies that are
2		relevant to distribution grid investments, costs,
3		planning, and other categories as requested by the
4		Commission.
5		The Plan shall comprehensively detail the relationship
6		between these plans, tariffs, and programs and to the
7		electric utility's achievement of the objectives in
8		subsection (d). The Plan shall be designed to coordinate
9		each of these plans, programs, and tariffs with the
10		electric utility's long-term distribution system
11		investment planning in order to maximize the benefits of
12		each.
13		(5) The initiating order for the initial Multi-Year
14		Integrated Grid Plan, as well as each electric utility's
15		subsequent Integrated Grid Plans under subsection (g),
16		shall begin a contested proceeding as described in
17		subsection (d) of Section 10-101.1 of this Act.
18		(A) In evaluating a utility's Plan, the Commission
19		shall consider, at minimum, whether the Plan:
20		(1) meets the objectives of this Section;
21		(2) includes the components in paragraph (2)
22		of subsection (f) of this Section;
23		(3) considers and incorporates, where
24		practicable, input from interested stakeholders,
25		including parties and people who offer public
26		comment without legal representation;

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1		(4) considers nontraditional, including
2		third-party owned, investment alternatives that
3		can meet grid needs and provide additional
4		benefits (including consumer, economic, and
5		environmental benefits) beyond comparable,
6		traditional utility-planned capital investments;
7		(5) equitably benefits environmental justice
8		communities; and
9		(6) maximizes consumer, environmental,
10		economic, and community benefits over a 10-year
11		horizon.
12		(B) The Commission, after notice and hearing,
13		shall modify each electric utility's Plan as necessary
14		to comply with the objectives of this Section. The
15		Commission may approve, or modify and approve, a Plan
16		only if it finds that the Plan is reasonable, complies
17		with the objectives and requirements of this Section,
18		and reasonably incorporates input from parties. The
19		Commission may reject each electric utility's Plan if
20		it finds that the Plan does not comply with the
21		objectives and requirements of this Section. If the
22		Commission enters an order rejecting a Plan, the
23		utility must refile a Plan within 3 months after that
24		order, and until the Commission approves a Plan, the
25		utility's existing Plan will remain in effect.
26		(C) For the initial Integrated Grid Plan filings,

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1		the Commission shall enter an order approving,
2		modifying, or rejecting the Plan no later than
3		December 15, 2023. For subsequent Integrated Grid Plan
4		filings, the Commission shall enter an order
5		approving, modifying, or rejecting the Plan no later
6		than December 15 of the year in which it was filed.
7		(D) Each electric utility shall file its proposed
8		Initial Multi-Year Integrated Grid Plan no later than
9		January 20, 2023. Prior to that date and following the
10		initiating order, the Commission shall initiate a case
11		management conference and shall take any appropriate
12		steps to begin meaningful consideration of issues,
13		including enabling interested parties to begin
14		conducting discovery.
15		(6) As part of its order approving a utility's
16		Multi-Year Integrated Grid Plan, including any
17		modifications required, the Commission may create a
18		subsequent implementation plan docket, or multiple
19		implementation plan dockets, if the Commission determines
20		that multiple dockets would be preferable, to consider a
21		utility's detailed plan or plans, as directed in the
22		Commission's order.
23		(g) No later than January 20, 2026 and every 4 years
24		thereafter, each electric utility subject to this Section
25		shall file a new Multi-Year Integrated Grid Plan for the
26		subsequent 4 delivery years after the completion of the

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1		then-effective Plan. Each Plan shall meet the requirements
2		described in subsection (f) of this Section, and shall be
3		preceded by a workshop process which meets the same
4		requirements described in subsection (e). If appropriate, the
5		Commission may require additional implementation dockets to
6		follow Subsequent Multi-Year Integrated Grid Plan filings.
7		(h) During the period leading to approval of the first
8		Multi-Year Integrated Grid Plan, each electric utility will
9		necessarily continue to invest in its distribution grid. Those
10		investments will be subject to a determination of prudence and
11		reasonableness consistent with Commission practice and law.
12		Any failure of such investments to conform to the Multi-Year
13		Integrated Grid Plan ultimately approved shall not imply
14		imprudence or unreasonableness.
15		(i) The Commission shall adopt rules to carry out the
16		provisions of this Section under the emergency rulemaking
17		provisions set forth in Section 5-45 of the Illinois
18		Administrative Procedure Act, and such emergency rules may be
19		effective no later than 90 days after the effective date of
20		this amendatory Act of the 102nd General Assembly.
21		(Source: P.A. 102-662, eff. 9-15-21.)
22		(220 ILCS 5/16-107.5)
23		Sec. 16-107.5. Net electricity metering.
24		(a) The General Assembly finds and declares that a program
25		to provide net electricity metering, as defined in this

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1		Section, for eligible customers can encourage private
2		investment in renewable energy resources, stimulate economic
3		growth, enhance the continued diversification of Illinois'
4		energy resource mix, and protect the Illinois environment.
5		Further, to achieve the goals of this Act that robust options
6		for customer-site distributed generation and storage continue
7		to thrive in Illinois, the General Assembly finds that a
8		predictable transition must be ensured for customers between
9		full net metering at the retail electricity rate to the
10		distribution generation rebate described in Section 16-107.6.
11		(b) As used in this Section: ,
12		(i) "Community community renewable generation project"
13		shall have the meaning set forth in Section 1-10 of the
14		Illinois Power Agency Act. ;
15		(ii) "Eligible eligible customer" means a retail
16		customer that owns, hosts, or operates, including any
17		third-party owned systems, a solar, wind, or other
18		eligible renewable electrical generating facility or an
19		eligible storage device that is located on the customer's
20		premises or customer's side of the billing meter and is
21		intended primarily to offset the customer's own current or
22		future electrical requirements. ;
23		(iii) "Electricity electricity provider" means an
24		electric utility or alternative retail electric supplier. ;
25		(iv) "Eligible eligible renewable electrical
26		generating facility" means a generator, which may include

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1		the colocation co-location of an energy storage system,
2		that is interconnected under rules adopted by the
3		Commission and is powered by solar electric energy, wind,
4		dedicated crops grown for electricity generation,
5		agricultural residues, untreated and unadulterated wood
6		waste, livestock manure, anaerobic digestion of livestock
7		or food processing waste, fuel cells or microturbines
8		powered by renewable fuels, or hydroelectric energy. ;
9		(v) "Net net electricity metering" (or "net metering")
10		means the measurement, during the billing period
11		applicable to an eligible customer, of the net amount of
12		electricity supplied by an electricity provider to the
13		customer or provided to the electricity provider by the
14		customer or subscriber. ;
15		(vi) "Subscriber subscriber" shall have the meaning as
16		set forth in Section 1-10 of the Illinois Power Agency
17		Act. ;
18		(vii) "Subscription subscription" shall have the
19		meaning set forth in Section 1-10 of the Illinois Power
20		Agency Act. ;
21		(viii) "Energy energy storage system" means
22		commercially available technology that is capable of
23		absorbing energy and storing it for a period of time for
24		use at a later time, including, but not limited to,
25		electrochemical, thermal, and electromechanical
26		technologies, and may be interconnected behind the

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1		customer's meter or interconnected behind its own meter. ;
2		and
3		(ix) "Future future electrical requirements" means
4		modeled electrical requirements upon occupation of a new
5		or vacant property, and other reasonable expectations of
6		future electrical use, as well as, for occupied
7		properties, a reasonable approximation of the annual load
8		of 2 electric vehicles and, for non-electric heating
9		customers, a reasonable approximation of the incremental
10		electric load associated with fuel switching. The
11		approximations shall be applied to the appropriate net
12		metering tariff and do not need to be unique to each
13		individual eligible customer. The utility shall submit
14		these approximations to the Commission for review,
15		modification, and approval.
16		(x) "Vehicle storage system" means a vehicle that when
17		connected to an electric utility's distribution system is
18		capable of being an energy storage system, as defined in
19		Section 16-107.6.
20		(c) A net metering facility shall be equipped with
21		metering equipment that can measure the flow of electricity in
22		both directions at the same rate.
23		(1) For eligible customers whose electric service has
24		not been declared competitive pursuant to Section 16-113
25		of this Act as of July 1, 2011 and whose electric delivery
26		service is provided and measured on a kilowatt-hour basis

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

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

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1		(2) If the amount of electricity produced by a
2		customer during the billing period exceeds the amount of
3		electricity used by the customer during that billing
4		period, the electricity provider supplying that customer
5		shall apply a 1:1 kilowatt-hour credit to a subsequent
6		bill for service to the customer for the net electricity
7		supplied to the electricity provider. The electricity
8		provider shall continue to carry over any excess
9		kilowatt-hour credits earned and apply those credits to
10		subsequent billing periods to offset any
11		customer-generator consumption in those billing periods
12		until all credits are used or until the end of the
13		annualized period.
14		(3) At the end of the year or annualized over the
15		period that service is supplied by means of net metering,
16		or in the event that the retail customer terminates
17		service with the electricity provider prior to the end of
18		the year or the annualized period, any remaining credits
19		in the customer's account shall expire.
20		(d-5) An electricity provider shall measure and charge or
21		credit for the net electricity supplied to eligible customers
22		or provided by eligible customers whose electric service has
23		not been declared competitive pursuant to Section 16-113 of
24		this Act as of July 1, 2011 and whose electric delivery service
25		is provided and measured on a kilowatt-hour basis and electric
26		supply service is provided based on hourly pricing or

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

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

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1		those billing periods until all credits are used or until
2		the end of the annualized period.
3		(3) At the end of the year or annualized over the
4		period that service is supplied by means of net metering,
5		or in the event that the retail customer terminates
6		service with the electricity provider prior to the end of
7		the year or the annualized period, any remaining credits
8		in the customer's account shall expire.
9		(e-5) An electricity provider shall provide electric
10		service to eligible customers who utilize net metering at
11		non-discriminatory rates that are identical, with respect to
12		rate structure, retail rate components, and any monthly
13		charges, to the rates that the customer would be charged if not
14		a net metering customer. An electricity provider shall not
15		charge net metering customers any fee or charge or require
16		additional equipment, insurance, or any other requirements not
17		specifically authorized by interconnection standards
18		authorized by the Commission, unless the fee, charge, or other
19		requirement would apply to other similarly situated customers
20		who are not net metering customers. The customer will remain
21		responsible for all taxes, fees, and utility delivery charges
22		that would otherwise be applicable to the net amount of
23		electricity used by the customer. Subsections (c) through (e)
24		of this Section shall not be construed to prevent an
25		arms-length agreement between an electricity provider and an
26		eligible customer that sets forth different prices, terms, and

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1		conditions for the provision of net metering service,
2		including, but not limited to, the provision of the
3		appropriate metering equipment for non-residential customers.
4		(f) Notwithstanding the requirements of subsections (c)
5		through (e-5) of this Section, an electricity provider must
6		require dual-channel metering for customers operating eligible
7		renewable electrical generating facilities to whom the
8		provisions of neither subsection (d), (d-5), nor (e) of this
9		Section apply. In such cases, electricity charges and credits
10		shall be determined as follows:
11		(1) The electricity provider shall assess and the
12		customer remains responsible for all taxes, fees, and
13		utility delivery charges that would otherwise be
14		applicable to the gross amount of kilowatt-hours supplied
15		to the eligible customer by the electricity provider.
16		(2) Each month that service is supplied by means of
17		dual-channel metering, the electricity provider shall
18		compensate the eligible customer for any excess
19		kilowatt-hour credits at the electricity provider's
20		avoided cost of electricity supply over the monthly period
21		or as otherwise specified by the terms of a power-purchase
22		agreement negotiated between the customer and electricity
23		provider.
24		(3) For all eligible net metering customers taking
25		service from an electricity provider under contracts or
26		tariffs employing hourly or time-of-use rates, any monthly

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1		consumption of electricity shall be calculated according
2		to the terms of the contract or tariff to which the same
3		customer would be assigned to or be eligible for if the
4		customer was not a net metering customer. When those same
5		customer-generators are net generators during any discrete
6		hourly or time-of-use period, the net kilowatt-hours
7		produced shall be valued at the same price per
8		kilowatt-hour as the electric service provider would
9		charge for retail kilowatt-hour sales during that same
10		time-of-use period.
11		(g) For purposes of federal and State laws providing
12		renewable energy credits or greenhouse gas credits, the
13		eligible customer shall be treated as owning and having title
14		to the renewable energy attributes, renewable energy credits,
15		and greenhouse gas emission credits related to any electricity
16		produced by the qualified generating unit. The electricity
17		provider may not condition participation in a net metering
18		program on the signing over of a customer's renewable energy
19		credits; provided, however, this subsection (g) shall not be
20		construed to prevent an arms-length agreement between an
21		electricity provider and an eligible customer that sets forth
22		the ownership or title of the credits.
23		(h) Within 120 days after the effective date of this
24		amendatory Act of the 95th General Assembly, the Commission
25		shall establish standards for net metering and, if the
26		Commission has not already acted on its own initiative,

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1		standards for the interconnection of eligible renewable
2		generating equipment to the utility system. The
3		interconnection standards shall address any procedural
4		barriers, delays, and administrative costs associated with the
5		interconnection of customer-generation while ensuring the
6		safety and reliability of the units and the electric utility
7		system. The Commission shall consider the Institute of
8		Electrical and Electronics Engineers (IEEE) Standard 1547 and
9		the issues of (i) reasonable and fair fees and costs, (ii)
10		clear timelines for major milestones in the interconnection
11		process, (iii) nondiscriminatory terms of agreement, and (iv)
12		any best practices for interconnection of distributed
13		generation.
14		(h-5) Within 90 days after the effective date of this
15		amendatory Act of the 102nd General Assembly, the Commission
16		shall:
17		(1) establish an Interconnection Working Group. The
18		working group shall include representatives from electric
19		utilities, developers of renewable electric generating
20		facilities, other industries that regularly apply for
21		interconnection with the electric utilities,
22		representatives of distributed generation customers, the
23		Commission Staff, and such other stakeholders with a
24		substantial interest in the topics addressed by the
25		Interconnection Working Group. The Interconnection Working
26		Group shall address at least the following issues:

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1		(A) cost and best available technology for
2		interconnection and metering, including the
3		standardization and publication of standard costs;
4		(B) transparency, accuracy and use of the
5		distribution interconnection queue and hosting
6		capacity maps;
7		(C) distribution system upgrade cost avoidance
8		through use of advanced inverter functions;
9		(D) predictability of the queue management process
10		and enforcement of timelines;
11		(E) benefits and challenges associated with group
12		studies and cost sharing;
13		(F) minimum requirements for application to the
14		interconnection process and throughout the
15		interconnection process to avoid queue clogging
16		behavior;
17		(G) process and customer service for
18		interconnecting customers adopting distributed energy
19		resources, including energy storage;
20		(H) options for metering distributed energy
21		resources, including energy storage;
22		(I) interconnection of new technologies, including
23		smart inverters and energy storage;
24		(J) collect, share, and examine data on Level 1
25		interconnection costs, including cost and type of
26		upgrades required for interconnection, and use this

SB0025 Enrolled - 701 - LRB104 07069 BAB 17106 b
1		data to inform the final standardized cost of Level 1
2		interconnection; and
3		(K) such other technical, policy, and tariff
4		issues related to and affecting interconnection
5		performance and customer service as determined by the
6		Interconnection Working Group.
7		The Commission may create subcommittees of the
8		Interconnection Working Group to focus on specific issues
9		of importance, as appropriate. The Interconnection Working
10		Group shall report to the Commission on recommended
11		improvements to interconnection rules and tariffs and
12		policies as determined by the Interconnection Working
13		Group at least every 6 months. Such reports shall include
14		consensus recommendations of the Interconnection Working
15		Group and, if applicable, additional recommendations for
16		which consensus was not reached. The Commission shall use
17		the report from the Interconnection Working Group to
18		determine whether processes should be commenced to
19		formally codify or implement the recommendations;
20		(2) create or contract for an Ombudsman to resolve
21		interconnection disputes through non-binding arbitration.
22		The Ombudsman may be paid in full or in part through fees
23		levied on the initiators of the dispute; and
24		(3) determine a single standardized cost for Level 1
25		interconnections, which shall not exceed $200.
26		(i) All electricity providers shall begin to offer net

SB0025 Enrolled - 702 - LRB104 07069 BAB 17106 b
1		metering no later than April 1, 2008.
2		(j) An electricity provider shall provide net metering to
3		eligible customers according to subsections (d), (d-5), and
4		(e). Eligible renewable electrical generating facilities for
5		which eligible customers registered for net metering before
6		January 1, 2025 shall continue to receive net metering
7		services according to subsections (d), (d-5), and (e) of this
8		Section for the lifetime of the system, regardless of whether
9		those retail customers change electricity providers or whether
10		the retail customer benefiting from the system changes. On and
11		after January 1, 2025, any eligible customer that applies for
12		net metering and previously would have qualified under
13		subsections (d), (d-5), or (e) shall only be eligible for net
14		metering as described in subsection (n).
15		(k) Each electricity provider shall maintain records and
16		report annually to the Commission the total number of net
17		metering customers served by the provider, as well as the
18		type, capacity, and energy sources of the generating systems
19		used by the net metering customers. Nothing in this Section
20		shall limit the ability of an electricity provider to request
21		the redaction of information deemed by the Commission to be
22		confidential business information.
23		(l)(1) Notwithstanding the definition of "eligible
24		customer" in item (ii) of subsection (b) of this Section, each
25		electricity provider shall allow net metering as set forth in
26		this subsection (l) and for the following projects, provided

SB0025 Enrolled - 703 - LRB104 07069 BAB 17106 b
1		that only electric utilities serving more than 200,000
2		customers as of January 1, 2021 shall provide net metering for
3		projects that are eligible for subparagraph (C) of this
4		paragraph (1) and have energized after the effective date of
5		this amendatory Act of the 102nd General Assembly:
6		(A) properties owned or leased by multiple customers
7		that contribute to the operation of an eligible renewable
8		electrical generating facility through an ownership or
9		leasehold interest of at least 200 watts in such facility,
10		such as a community-owned wind project, a community-owned
11		biomass project, a community-owned solar project, or a
12		community methane digester processing livestock waste from
13		multiple sources, provided that the facility is also
14		located within the utility's service territory;
15		(B) individual units, apartments, or properties
16		located in a single building that are owned or leased by
17		multiple customers and collectively served by a common
18		eligible renewable electrical generating facility, such as
19		an office or apartment building, a shopping center or
20		strip mall served by photovoltaic panels on the roof; and
21		(C) subscriptions to community renewable generation
22		projects, including community renewable generation
23		projects on the customer's side of the billing meter of a
24		host facility and partially used for the customer's own
25		load.
26		In addition, the nameplate capacity of the eligible

SB0025 Enrolled - 704 - LRB104 07069 BAB 17106 b
1		renewable electric generating facility that serves the demand
2		of the properties, units, or apartments identified in
3		paragraphs (1) and (2) of this subsection (l) shall not exceed
4		5,000 kilowatts in nameplate capacity in total. Any eligible
5		renewable electrical generating facility or community
6		renewable generation project that is powered by photovoltaic
7		electric energy and installed after the effective date of this
8		amendatory Act of the 99th General Assembly must be installed
9		by a qualified person in compliance with the requirements of
10		Section 16-128A of the Public Utilities Act and any rules or
11		regulations adopted thereunder.
12		(2) Notwithstanding anything to the contrary, an
13		electricity provider shall provide credits for the electricity
14		produced by the projects described in paragraph (1) of this
15		subsection (l). The electricity provider shall provide credits
16		that include at least energy supply, capacity, transmission,
17		and, if applicable, the purchased energy adjustment on the
18		subscriber's monthly bill equal to the subscriber's share of
19		the production of electricity from the project, as determined
20		by paragraph (3) of this subsection (l). For customers with
21		transmission or capacity charges not charged on a
22		kilowatt-hour basis, the electricity provider shall prepare a
23		reasonable approximation of the kilowatt-hour equivalent value
24		and provide that value as a monetary credit. The electricity
25		provider shall submit these approximation methodologies to the
26		Commission for review, modification, and approval.

SB0025 Enrolled - 705 - LRB104 07069 BAB 17106 b
1		Notwithstanding anything to the contrary, customers on payment
2		plans or participating in budget billing programs shall have
3		credits applied on a monthly basis.
4		(3) Notwithstanding anything to the contrary and
5		regardless of whether a subscriber to an eligible community
6		renewable generation project receives power and energy service
7		from the electric utility or an alternative retail electric
8		supplier, for projects eligible under paragraph (C) of
9		subparagraph (1) of this subsection (l), electric utilities
10		serving more than 200,000 customers as of January 1, 2021
11		shall provide the monetary credits to a subscriber's
12		subsequent bill for the electricity produced by community
13		renewable generation projects. The electric utility shall
14		provide monetary credits to a subscriber's subsequent bill at
15		the utility's total price to compare equal to the subscriber's
16		share of the production of electricity from the project, as
17		determined by paragraph (5) of this subsection (l). For the
18		purposes of this subsection, "total price to compare" means
19		the rate or rates published by the Illinois Commerce
20		Commission for energy supply for eligible customers receiving
21		supply service from the electric utility, and shall include
22		energy, capacity, transmission, and the purchased energy
23		adjustment. Notwithstanding anything to the contrary,
24		customers on payment plans or participating in budget billing
25		programs shall have credits applied on a monthly basis. Any
26		applicable credit or reduction in load obligation from the

SB0025 Enrolled - 706 - LRB104 07069 BAB 17106 b
1		production of the community renewable generating projects
2		receiving a credit under this subsection shall be credited to
3		the electric utility to offset the cost of providing the
4		credit. To the extent that the credit or load obligation
5		reduction does not completely offset the cost of providing the
6		credit to subscribers of community renewable generation
7		projects as described in this subsection, the electric utility
8		may recover the remaining costs through its Multi-Year Rate
9		Plan. All electric utilities serving 200,000 or fewer
10		customers as of January 1, 2021 shall only provide the
11		monetary credits to a subscriber's subsequent bill for the
12		electricity produced by community renewable generation
13		projects if the subscriber receives power and energy service
14		from the electric utility. Alternative retail electric
15		suppliers providing power and energy service to a subscriber
16		located within the service territory of an electric utility
17		not subject to Sections 16-108.18 and 16-118 shall provide the
18		monetary credits to the subscriber's subsequent bill for the
19		electricity produced by community renewable generation
20		projects.
21		(4) If requested by the owner or operator of a community
22		renewable generating project, an electric utility serving more
23		than 200,000 customers as of January 1, 2021 shall enter into a
24		net crediting agreement with the owner or operator to include
25		a subscriber's subscription fee on the subscriber's monthly
26		electric bill and provide the subscriber with a net credit

SB0025 Enrolled - 707 - LRB104 07069 BAB 17106 b
1		equivalent to the total bill credit value for that generation
2		period minus the subscription fee, provided the subscription
3		fee is structured as a fixed percentage of bill credit value.
4		The net crediting agreement shall set forth payment terms from
5		the electric utility to the owner or operator of the community
6		renewable generating project, and the electric utility may
7		charge a net crediting fee to the owner or operator of a
8		community renewable generating project that may not exceed 1%
9		2% of the subscription fee bill credit value. Notwithstanding
10		anything to the contrary, an electric utility serving 200,000
11		customers or fewer as of January 1, 2021 shall not be obligated
12		to enter into a net crediting agreement with the owner or
13		operator of a community renewable generating project. An
14		electric utility shall use the same net crediting format for
15		subscribers on payment plans and subscribers participating in
16		budget billing programs. For the purposes of this paragraph
17		(4), "net crediting" means a program offered by an electric
18		utility under which the electric utility, upon authorization
19		by or on behalf of a subscriber, remits the cash value of the
20		subscription fee to the owner or operator of the community
21		renewable generation facility without regard to whether the
22		subscriber has paid the subscriber's monthly electric bill and
23		places the cash value of the remaining bill credit on the
24		subscriber's bill.
25		(5) For the purposes of facilitating net metering, the
26		owner or operator of the eligible renewable electrical

SB0025 Enrolled - 708 - LRB104 07069 BAB 17106 b
1		generating facility or community renewable generation project
2		shall be responsible for determining the amount of the credit
3		that each customer or subscriber participating in a project
4		under this subsection (l) is to receive in the following
5		manner:
6		(A) The owner or operator shall, on a monthly basis,
7		provide to the electric utility the kilowatthours of
8		generation attributable to each of the utility's retail
9		customers and subscribers participating in projects under
10		this subsection (l) in accordance with the customer's or
11		subscriber's share of the eligible renewable electric
12		generating facility's or community renewable generation
13		project's output of power and energy for such month. The
14		owner or operator shall electronically transmit such
15		calculations and associated documentation to the electric
16		utility, in a format or method set forth in the applicable
17		tariff, on a monthly basis so that the electric utility
18		can reflect the monetary credits on customers' and
19		subscribers' electric utility bills. The electric utility
20		shall be permitted to revise its tariffs to implement the
21		provisions of this amendatory Act of the 102nd General
22		Assembly. The owner or operator shall separately provide
23		the electric utility with the documentation detailing the
24		calculations supporting the credit in the manner set forth
25		in the applicable tariff.
26		(B) For those participating customers and subscribers

SB0025 Enrolled - 709 - LRB104 07069 BAB 17106 b
1		who receive their energy supply from an alternative retail
2		electric supplier, the electric utility shall remit to the
3		applicable alternative retail electric supplier the
4		information provided under subparagraph (A) of this
5		paragraph (3) for such customers and subscribers in a
6		manner set forth in such alternative retail electric
7		supplier's net metering program, or as otherwise agreed
8		between the utility and the alternative retail electric
9		supplier. The alternative retail electric supplier shall
10		then submit to the utility the amount of the charges for
11		power and energy to be applied to such customers and
12		subscribers, including the amount of the credit associated
13		with net metering.
14		(C) A participating customer or subscriber may provide
15		authorization as required by applicable law that directs
16		the electric utility to submit information to the owner or
17		operator of the eligible renewable electrical generating
18		facility or community renewable generation project to
19		which the customer or subscriber has an ownership or
20		leasehold interest or a subscription. Such information
21		shall be limited to the components of the net metering
22		credit calculated under this subsection (l), including the
23		bill credit rate, total kilowatthours, and total monetary
24		credit value applied to the customer's or subscriber's
25		bill for the monthly billing period.
26		(l-5) Within 90 days after the effective date of this

SB0025 Enrolled - 710 - LRB104 07069 BAB 17106 b
1		amendatory Act of the 102nd General Assembly, each electric
2		utility subject to this Section shall file a tariff or tariffs
3		to implement the provisions of subsection (l) of this Section,
4		which shall, consistent with the provisions of subsection (l),
5		describe the terms and conditions under which owners or
6		operators of qualifying properties, units, or apartments may
7		participate in net metering. The Commission shall approve, or
8		approve with modification, the tariff within 120 days after
9		the effective date of this amendatory Act of the 102nd General
10		Assembly.
11		(l-10) Within 30 days after the effective date of this
12		amendatory Act of the 104th General Assembly, each electricity
13		provider shall modify its tariffs to allow net metering as set
14		forth in this subsection for an energy storage system or
15		vehicle storage system energized after the effective date of
16		this amendatory Act of the 104th General Assembly with a
17		nameplate capacity of not more than 5,000 kilowatts. If the
18		Commission chooses to suspend the modified tariffs, the
19		Commission shall issue a final order approving, or approving
20		with modification, the modified tariffs no later than 90 days
21		after the Commission initiates the docket.
22		An energy storage system or vehicle storage system
23		eligible for net metering under this subsection may be
24		interconnected behind the meter of a retail customer or at the
25		distribution system level of an electric utility as follows:
26		(A) if the energy storage system or vehicle storage

SB0025 Enrolled - 711 - LRB104 07069 BAB 17106 b
1		system is interconnected behind the meter of a retail
2		customer, in order to receive net metering under this
3		subsection, the eligible customer behind whose meter the
4		energy storage system is interconnected must receive
5		service from an electricity provider under an hourly
6		supply tariff, a time-of-use supply tariff, or a
7		time-of-use contract with an alternative retail electric
8		supplier; or
9		(B) if the energy storage system or vehicle storage
10		system is interconnected at the distribution system level
11		of an electric utility and not behind the meter of a retail
12		customer, the energy storage system or vehicle storage
13		system must receive service from an electricity provider
14		as a retail customer under an hourly supply tariff
15		authorized by Section 16-107, a supply tariff or contract
16		on substantially similar terms and conditions with an
17		alternative retail electric supplier, a time-of-use supply
18		tariff, or a time-of-use supply contract with an
19		alternative retail electric supplier.
20		If the energy storage system or vehicle storage system is
21		interconnected behind the meter of an eligible customer, the
22		eligible customer shall receive net metering based on hourly
23		or time-of-use rates in accordance with the terms of
24		subsection (d-5) or (f) or paragraph (2) of subsection (n) of
25		this Section, as applicable to the eligible customer. If the
26		energy storage system or vehicle storage system is

SB0025 Enrolled - 712 - LRB104 07069 BAB 17106 b
1		interconnected at the distribution system level of an electric
2		utility and not behind the meter of a retail customer, then the
3		energy storage system or vehicle storage system shall receive
4		net metering pursuant to the terms of subsection (f) of this
5		Section.
6		(m) Nothing in this Section shall affect the right of an
7		electricity provider to continue to provide, or the right of a
8		retail customer to continue to receive service pursuant to a
9		contract for electric service between the electricity provider
10		and the retail customer in accordance with the prices, terms,
11		and conditions provided for in that contract. Either the
12		electricity provider or the customer may require compliance
13		with the prices, terms, and conditions of the contract.
14		(n) On and after January 1, 2025, the net metering
15		services described in subsections (d), (d-5), and (e) of this
16		Section shall no longer be offered, except as to those
17		eligible renewable electrical generating facilities for which
18		retail customers are receiving net metering service under
19		these subsections at the time the net metering services under
20		those subsections are no longer offered; those systems shall
21		continue to receive net metering services described in
22		subsections (d), (d-5), and (e) of this Section for the
23		lifetime of the system, regardless of if those retail
24		customers change electricity providers or whether the retail
25		customer benefiting from the system changes. The electric
26		utility serving more than 200,000 customers as of January 1,

SB0025 Enrolled - 713 - LRB104 07069 BAB 17106 b
1		2021 is responsible for ensuring the billing credits continue
2		without lapse for the lifetime of systems, as required in
3		subsection (o). Those retail customers that begin taking net
4		metering service after the date that net metering services are
5		no longer offered under such subsections shall be subject to
6		the provisions set forth in the following paragraphs (1)
7		through (3) of this subsection (n):
8		(1) An electricity provider shall charge or credit for
9		the net electricity supplied to eligible customers or
10		provided by eligible customers whose electric supply
11		service is not provided based on hourly pricing in the
12		following manner:
13		(A) If the amount of electricity used by the
14		customer during the monthly billing period exceeds the
15		amount of electricity produced by the customer, then
16		the electricity provider shall charge the customer for
17		the net kilowatt-hour based electricity charges
18		reflected in the customer's electric service rate
19		supplied to and used by the customer as provided in
20		paragraph (3) of this subsection (n).
21		(B) If the amount of electricity produced by a
22		customer during the monthly billing period exceeds the
23		amount of electricity used by the customer during that
24		billing period, then the electricity provider
25		supplying that customer shall apply a 1:1
26		kilowatt-hour energy or monetary credit kilowatt-hour

SB0025 Enrolled - 714 - LRB104 07069 BAB 17106 b
1		supply charges to the customer's subsequent bill. The
2		customer shall choose between 1:1 kilowatt-hour or
3		monetary credit at the time of application. For the
4		purposes of this subsection, "kilowatt-hour supply
5		charges" means the kilowatt-hour equivalent values for
6		energy, capacity, transmission, and the purchased
7		energy adjustment, if applicable. Notwithstanding
8		anything to the contrary, customers on payment plans
9		or participating in budget billing programs shall have
10		credits applied on a monthly basis. The electricity
11		provider shall continue to carry over any excess
12		kilowatt-hour or monetary energy credits earned and
13		apply those credits to subsequent billing periods. For
14		customers with transmission or capacity charges not
15		charged on a kilowatt-hour basis, the electricity
16		provider shall prepare a reasonable approximation of
17		the kilowatt-hour equivalent value and provide that
18		value as a monetary credit. The electricity provider
19		shall submit these approximation methodologies to the
20		Commission for review, modification, and approval.
21		(C) (Blank).
22		(2) An electricity provider shall charge or credit for
23		the net electricity supplied to eligible customers or
24		provided by eligible customers whose electric supply
25		service is provided based on hourly pricing in the
26		following manner:

SB0025 Enrolled - 715 - LRB104 07069 BAB 17106 b
1		(A) If the amount of electricity used by the
2		customer during any hourly period exceeds the amount
3		of electricity produced by the customer, then the
4		electricity provider shall charge the customer for the
5		net electricity supplied to and used by the customer
6		as provided in paragraph (3) of this subsection (n).
7		(B) If the amount of electricity produced by a
8		customer during any hourly period exceeds the amount
9		of electricity used by the customer during that hourly
10		period, the energy provider shall calculate an energy
11		credit for the net kilowatt-hours produced in such
12		period, and shall apply that credit as a monetary
13		credit to the customer's subsequent bill. The value of
14		the energy credit shall be calculated using the same
15		price per kilowatt-hour as the electric service
16		provider would charge for kilowatt-hour energy sales
17		during that same hourly period and shall also include
18		values for capacity and transmission. For customers
19		with transmission or capacity charges not charged on a
20		kilowatt-hour basis, the electricity provider shall
21		prepare a reasonable approximation of the
22		kilowatt-hour equivalent value and provide that value
23		as a monetary credit. The electricity provider shall
24		submit these approximation methodologies to the
25		Commission for review, modification, and approval.
26		Notwithstanding anything to the contrary, customers on

SB0025 Enrolled - 716 - LRB104 07069 BAB 17106 b
1		payment plans or participating in budget billing
2		programs shall have credits applied on a monthly
3		basis.
4		(3) An electricity provider shall provide electric
5		service to eligible customers who utilize net metering at
6		non-discriminatory rates that are identical, with respect
7		to rate structure, retail rate components, and any monthly
8		charges, to the rates that the customer would be charged
9		if not a net metering customer. An electricity provider
10		shall charge the customer for the net electricity supplied
11		to and used by the customer according to the terms of the
12		contract or tariff to which the same customer would be
13		assigned or be eligible for if the customer was not a net
14		metering customer. An electricity provider shall not
15		charge net metering customers any fee or charge or require
16		additional equipment, insurance, or any other requirements
17		not specifically authorized by interconnection standards
18		authorized by the Commission, unless the fee, charge, or
19		other requirement would apply to other similarly situated
20		customers who are not net metering customers. The customer
21		remains responsible for the gross amount of delivery
22		services charges, supply-related charges that are kilowatt
23		based, and all taxes and fees related to such charges. The
24		customer also remains responsible for all taxes and fees
25		that would otherwise be applicable to the net amount of
26		electricity used by the customer. Paragraphs (1) and (2)

SB0025 Enrolled - 717 - LRB104 07069 BAB 17106 b
1		of this subsection (n) shall not be construed to prevent
2		an arms-length agreement between an electricity provider
3		and an eligible customer that sets forth different prices,
4		terms, and conditions for the provision of net metering
5		service, including, but not limited to, the provision of
6		the appropriate metering equipment for non-residential
7		customers. Nothing in this paragraph (3) shall be
8		interpreted to mandate that a utility that is only
9		required to provide delivery services to a given customer
10		must also sell electricity to such customer.
11		(o) Within 90 days after the effective date of this
12		amendatory Act of the 102nd General Assembly, each electric
13		utility subject to this Section shall file a tariff, which
14		shall, consistent with the provisions of this Section, propose
15		the terms and conditions under which a customer may
16		participate in net metering. The tariff for electric utilities
17		serving more than 200,000 customers as of January 1, 2021
18		shall also provide a streamlined and transparent bill
19		crediting system for net metering to be managed by the
20		electric utilities. The terms and conditions shall include,
21		but are not limited to, that an electric utility shall manage
22		and maintain billing of net metering credits and charges
23		regardless of if the eligible customer takes net metering
24		under an electric utility or alternative retail electric
25		supplier. The electric utility serving more than 200,000
26		customers as of January 1, 2021 shall process and approve all

SB0025 Enrolled - 718 - LRB104 07069 BAB 17106 b
1		net metering applications, even if an eligible customer is
2		served by an alternative retail electric supplier; and the
3		utility shall forward application approval to the appropriate
4		alternative retail electric supplier. Eligibility for net
5		metering shall remain with the owner of the utility billing
6		address such that, if an eligible renewable electrical
7		generating facility changes ownership, the net metering
8		eligibility transfers to the new owner. The electric utility
9		serving more than 200,000 customers as of January 1, 2021
10		shall manage net metering billing for eligible customers to
11		ensure full crediting occurs on electricity bills, including,
12		but not limited to, ensuring net metering crediting begins
13		upon commercial operation date, net metering billing transfers
14		immediately if an eligible customer switches from an electric
15		utility to alternative retail electric supplier or vice versa,
16		and net metering billing transfers between ownership of a
17		valid billing address. All transfers referenced in the
18		preceding sentence shall include transfer of all banked
19		credits. All electric utilities serving 200,000 or fewer
20		customers as of January 1, 2021 shall manage net metering
21		billing for eligible customers receiving power and energy
22		service from the electric utility to ensure full crediting
23		occurs on electricity bills, ensuring net metering crediting
24		begins upon commercial operation date, net metering billing
25		transfers immediately if an eligible customer switches from an
26		electric utility to alternative retail electric supplier or

SB0025 Enrolled - 719 - LRB104 07069 BAB 17106 b
1		vice versa, and net metering billing transfers between
2		ownership of a valid billing address. Alternative retail
3		electric suppliers providing power and energy service to
4		eligible customers located within the service territory of an
5		electric utility serving 200,000 or fewer customers as of
6		January 1, 2021 shall manage net metering billing for eligible
7		customers to ensure full crediting occurs on electricity
8		bills, including, but not limited to, ensuring net metering
9		crediting begins upon commercial operation date, net metering
10		billing transfers immediately if an eligible customer switches
11		from an electric utility to alternative retail electric
12		supplier or vice versa, and net metering billing transfers
13		between ownership of a valid billing address.
14		(Source: P.A. 102-662, eff. 9-15-21.)
15		(220 ILCS 5/16-107.6)
16		Sec. 16-107.6. Distributed generation and storage rebate.
17		(a) In this Section:
18		"Additive services" means the services that distributed
19		energy resources provide to the energy system and society that
20		are described in Section 16-107.9 not (1) already included in
21		the base rebates for system-wide grid services; or (2)
22		otherwise already compensated. Additive services may reflect,
23		but shall not be limited to, any geographic, time-based,
24		performance-based, and other benefits of distributed energy
25		resources, as well as the present and future technological

SB0025 Enrolled - 720 - LRB104 07069 BAB 17106 b
1		capabilities of distributed energy resources and present and
2		future grid needs.
3		"Distributed energy resource" means a wide range of
4		technologies that are located on the customer side of the
5		customer's electric meter, including, but not limited to,
6		distributed generation, energy storage, electric vehicles, and
7		demand response technologies.
8		"Distributed storage" means energy storage systems that
9		are interconnected behind the customer's meter to the
10		distribution system or interconnected behind the storage
11		system's own meter to the distribution system.
12		"Energy storage system" means commercially available
13		technology that is capable of absorbing energy and storing it
14		for a period of time for use at a later time, including, but
15		not limited to, electrochemical, thermal, and
16		electromechanical technologies, and may be interconnected
17		behind the customer's meter or interconnected behind its own
18		meter.
19		"Smart inverter" means a device that converts direct
20		current into alternating current and meets the IEEE 1547-2018
21		equipment standards. Until devices that meet the IEEE
22		1547-2018 standard are available, devices that meet the UL
23		1741 SA standard are acceptable.
24		"Subscriber" has the meaning set forth in Section 1-10 of
25		the Illinois Power Agency Act.
26		"Subscription" has the meaning set forth in Section 1-10

SB0025 Enrolled - 721 - LRB104 07069 BAB 17106 b
1		of the Illinois Power Agency Act.
2		"System-wide grid services" means the benefits that a
3		distributed energy resource provides to the distribution grid
4		for a period of no less than 25 years. System-wide grid
5		services do not vary by location, time, or the performance
6		characteristics of the distributed energy resource.
7		System-wide grid services include, but are not limited to,
8		avoided or deferred distribution capacity costs, resilience
9		and reliability benefits, avoided or deferred distribution
10		operation and maintenance costs, distribution voltage and
11		power quality benefits, and line loss reductions.
12		"Threshold date" means the date 2 years after the
13		effective date of this amendatory Act of the 104th General
14		Assembly December 31, 2024 or the date on which the utility's
15		tariff or tariffs authorized by Section 16-107.9 setting the
16		new compensation values established under subsection (e) take
17		effect, whichever is later.
18		(b) An electric utility that serves more than 200,000
19		customers in the State shall file a petition with the
20		Commission requesting approval of the utility's tariff to
21		provide a rebate to the owner or operator of distributed
22		generation, including third-party owned systems, that meets
23		the 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, or as otherwise as defined

SB0025 Enrolled - 722 - LRB104 07069 BAB 17106 b
1		for community renewable generation projects in Section
2		1-10 of the Illinois Power Agency Act;
3		(2) is located on the customer's side of the billing
4		meter and for the customer's own use;
5		(3) is interconnected to electric distribution
6		facilities owned by the electric utility under rules
7		adopted by the Commission by means of one or more
8		inverters or smart inverters required by this Section, as
9		applicable.
10		For purposes of this Section, "distributed generation"
11		shall satisfy the definition of distributed renewable energy
12		generation device set forth in Section 1-10 of the Illinois
13		Power Agency Act to the extent such definition is consistent
14		with the requirements of this Section.
15		In addition, any new photovoltaic distributed generation
16		that is installed after June 1, 2017 (the effective date of
17		Public Act 99-906) must be installed by a qualified person, as
18		defined by subsection (i) of Section 1-56 of the Illinois
19		Power Agency Act.
20		The tariff shall include a base rebate that compensates
21		distributed generation for the system-wide grid services
22		associated with distributed generation and, after the
23		proceeding described in subsection (e) of this Section, an
24		additional payment or payments for any the additive services
25		identified by the Commission under Section 16-107.9. The
26		distributed generation and storage tariff shall provide that

SB0025 Enrolled - 723 - LRB104 07069 BAB 17106 b
1		the smart inverter or smart inverters associated with the
2		distributed generation shall provide autonomous response to
3		grid conditions through its default settings as approved by
4		the Commission. Default settings may not be changed after the
5		execution of the interconnection agreement except by mutual
6		agreement between the utility and the owner or operator of the
7		distributed generation. Nothing in this Section shall negate
8		or supersede Institute of Electrical and Electronics Engineers
9		equipment standards or other similar standards or
10		requirements. The tariff shall not limit the ability of the
11		smart inverter or smart inverters or other distributed energy
12		resource to provide wholesale market products such as
13		regulation, demand response, or other services, or limit the
14		ability of the owner of the smart inverter or the other
15		distributed energy resource to receive compensation for
16		providing those wholesale market products or services.
17		(b-5) Within 30 days after the effective date of this
18		amendatory Act of the 102nd General Assembly, each electric
19		public utility with 3,000,000 or more retail customers shall
20		file a tariff with the Commission that further compensates any
21		retail customer that installs or has installed photovoltaic
22		facilities paired with energy storage facilities on or
23		adjacent to its premises for the benefits the facilities
24		provide to the distribution grid. The tariff shall provide
25		that, in addition to the other rebates identified in this
26		Section, the electric utility shall rebate to such retail

SB0025 Enrolled - 724 - LRB104 07069 BAB 17106 b
1		customer (i) the previously incurred and future costs of
2		installing interconnection facilities and related
3		infrastructure to enable full participation in the PJM
4		Interconnection, LLC or its successor organization frequency
5		regulation market; and (ii) all wholesale demand charges
6		incurred after the effective date of this amendatory Act of
7		the 102nd General Assembly. The Commission shall approve, or
8		approve with modification, the tariff within 120 days after
9		the utility's filing.
10		To be eligible for a rebate described in this subsection
11		(b-5), the owner or operator of the distributed generation
12		shall provide proof of participation in the frequency
13		regulation market. Upon providing proof of participation, the
14		retail customer shall be entitled to a rebate equal to the cost
15		of the interconnection facilities paid to ComEd, regardless of
16		whether the retail customer would have incurred the
17		interconnection costs in the absence of participating in the
18		frequency regulation market, plus the cost of software,
19		telecommunications hardware, and telemetry paid to enable
20		communication with PJM for purposes of participating in the
21		frequency regulation market. A utility providing rebates
22		described in this subsection (b-5) shall be entitled to
23		recover the costs of the rebates as provided for in subsection
24		(h) of this Section. To the extent the electric utility's
25		tariff is modified to comply with this subsection (b-5), it
26		shall file a revised tariff with the Commission within 120

SB0025 Enrolled - 725 - LRB104 07069 BAB 17106 b
1		days after the effective date of this amendatory Act of the
2		104th General Assembly, and the Commission shall approve, or
3		approve with modification, the tariff within 240 days after
4		the Commission initiates the docket.
5		(c) The proposed tariff authorized by subsection (b) of
6		this Section shall include the following participation terms
7		for rebates to be applied under this Section for distributed
8		generation that satisfies the criteria set forth in subsection
9		(b) of this Section:
10		(1) The owner or operator of distributed generation or
11		distributed storage that services customers not eligible
12		for net metering under subsection (d), (d-5), or (e) of
13		Section 16-107.5 of this Act may apply for a rebate as
14		provided for in this Section. The Until the threshold
15		date, the value of the rebate shall be $250 per kilowatt of
16		nameplate generating capacity, measured as nominal DC
17		power output, of that customer's distributed generation.
18		To the extent the distributed generation also has an
19		associated energy storage, then until the threshold date
20		for systems other than community renewable generation
21		projects paired with an energy storage system, the energy
22		storage system shall be separately compensated with a base
23		rebate of $250 per kilowatt-hour of nameplate capacity. To
24		the extent that a community renewable generation project
25		is paired with an energy storage system or an energy
26		storage system that is paired with distributed generation,

SB0025 Enrolled - 726 - LRB104 07069 BAB 17106 b
1		the energy storage system shall be separately compensated
2		with a rebate of $250 per kilowatt-hour of nameplate
3		capacity. A stand-alone energy storage system shall be
4		compensated with a rebate of $250 per kilowatt-hour of
5		nameplate capacity. Any distributed generation device that
6		is compensated for storage in this subsection (1) after
7		the effective date of this amendatory Act of the 104th
8		General Assembly before the threshold date shall
9		participate in one or more programs authorized by
10		paragraph (1) of subsection (e). Compensation determined
11		through the Multi-Year Integrated Grid Planning process
12		that are designed to meet peak reduction and flexibility.
13		After the threshold date, the value of the base rebate and
14		additional compensation for any additive services shall be
15		as determined by the Commission in the proceeding
16		described in Section 16-107.9 subsection (e) of this
17		Section, provided that the value of the base rebate for
18		system-wide grid services shall not be lower than $250 per
19		kilowatt of nameplate generating capacity of distributed
20		generation or community renewable generation project. To
21		the extent that an electric utility's tariffs are
22		inconsistent with the requirements of this paragraph (1)
23		as modified by this amendatory Act of the 104th General
24		Assembly, the electric utility shall, within 60 days after
25		the effective date of this amendatory Act of the 104th
26		General Assembly, file modified tariffs consistent with

SB0025 Enrolled - 727 - LRB104 07069 BAB 17106 b
1		the requirements of this paragraph (1). If the Commission
2		chooses to suspend the modified tariffs following notice
3		and hearing, the Commission shall issue an order
4		approving, or approving with modification, the modified
5		tariffs no later than 90 days after the Commission
6		initiates the docket.
7		(2) The owner or operator of distributed generation
8		that, before the threshold date, would have been eligible
9		for net metering under subsection (d), (d-5), or (e) of
10		Section 16-107.5 of this Act and that has not previously
11		received a distributed generation rebate, may apply for a
12		rebate as provided for in this Section. Until December 31,
13		2029 the threshold date, the value of the base rebate
14		shall be $300 per kilowatt of nameplate generating
15		capacity, measured as nominal DC power output, of the
16		distributed generation. On or after January 1, 2030, the
17		value of the base rebate shall be $250 per kilowatt of
18		nameplate generating capacity, measured as nominal DC
19		power output, of the distributed generation. The owner or
20		operator of distributed generation that, before the
21		threshold date, is eligible for net metering under
22		subsection (d), (d-5), or (e) of Section 16-107.5 of this
23		Act may apply for a base rebate for an associated energy
24		storage device behind the same retail customer meter as
25		the distributed generation, regardless of whether the
26		distributed generation applies for a rebate for the

SB0025 Enrolled - 728 - LRB104 07069 BAB 17106 b
1		distributed generation device. An The energy storage
2		system, whether or not paired with distributed generation,
3		shall be separately compensated at a base payment of $300
4		per kilowatt-hour of nameplate capacity until the
5		threshold date. After the threshold date, a stand-alone
6		energy storage system shall be compensated with a rebate
7		of $250 per kilowatt-hour of nameplate capacity. Any
8		distributed generation device that is compensated for
9		storage in this subsection (2) has the option to before
10		the threshold date shall participate in either an a peak
11		time rebate program, hourly pricing program, or
12		time-of-use rate program and any distributed generation
13		device that is compensated for storage in this subsection
14		(2) after the effective date of this amendatory Act of the
15		104th General Assembly shall participate in a scheduled
16		dispatch program set forth in paragraph (1) of subsection
17		(e) when it becomes available offered by the applicable
18		electric utility. Compensation After the threshold date,
19		the value of the base rebate and additional compensation
20		for any additive services or other programs shall be as
21		determined by the Commission in the proceeding described
22		in Section 16-107.9 subsection (e) of this Section,
23		provided that, prior to December 31, 2029, the value of
24		the base rebate for system-wide services shall not be
25		lower than $300 per kilowatt of nameplate generating
26		capacity of distributed generation, after which it shall

SB0025 Enrolled - 729 - LRB104 07069 BAB 17106 b
1		not be lower than $250 per kilowatt of nameplate capacity.
2		The eligibility of energy storage devices that are
3		interconnected behind the same retail customer meter as
4		the distributed generation shall not be limited to energy
5		storage devices interconnected after the effective date of
6		this amendatory Act of the 103rd General Assembly. To the
7		extent that an electric utility's tariffs are inconsistent
8		with the requirements of this paragraph (2) as modified by
9		this amendatory Act of the 104th General Assembly this
10		amendatory Act of the 103rd General Assembly, such
11		electric utility shall, within 60 30 days, file modified
12		tariffs consistent with the requirements of this paragraph
13		(2).
14		(3) Upon approval of a rebate application submitted
15		under this subsection (c), the retail customer shall no
16		longer be entitled to receive any delivery service credits
17		for the excess electricity generated by its facility and
18		shall be subject to the provisions of subsection (n) of
19		Section 16-107.5 of this Act unless the owner or operator
20		receives a rebate only for an energy storage device and
21		not for the distributed generation device.
22		(4) To be eligible for a rebate described in this
23		subsection (c), the owner or operator of the distributed
24		generation must have a smart inverter installed and in
25		operation on the distributed generation.
26		(5) The owner or operator of any distributed

SB0025 Enrolled - 730 - LRB104 07069 BAB 17106 b
1		generation or distributed storage system whose electric
2		service has not been declared competitive under Section
3		16-113 as of July 1, 2011 or the owner or operator of a
4		community renewable generation project participating in
5		the Adjustable Block Program as a community-driven
6		community solar project as defined in item (v) of
7		subparagraph (K) of paragraph (1) of subsection (c) of
8		Section 1-75 of the Illinois Power Agency Act and that has
9		an interconnection agreement dated after the effective
10		date of this amendatory Act of the 104th General Assembly
11		shall be eligible for an additional payment or payments to
12		the applicable rebate under paragraphs (1) or (2) of this
13		subsection (c) in an amount set by tariff and approved by
14		the Commission if located in an equity investment eligible
15		community, as defined in Section 1-10 of the Illinois
16		Power Agency Act, at the time the interconnection
17		agreement is signed.
18		(d) The Commission shall review the proposed tariff
19		authorized by subsection (b) of this Section and may make
20		changes to the tariff that are consistent with this Section
21		and with the Commission's authority under Article IX of this
22		Act, subject to notice and hearing. Following notice and
23		hearing, the Commission shall issue an order approving, or
24		approving with modification, such tariff no later than 240
25		days after the utility files its tariff. Upon the effective
26		date of this amendatory Act of the 102nd General Assembly, an

SB0025 Enrolled - 731 - LRB104 07069 BAB 17106 b
1		electric utility shall file a petition with the Commission to
2		amend and update any existing tariffs to comply with
3		subsections (b) and (c).
4		(e) By no later than June 30, 2026 June 30, 2023, the
5		Commission shall establish a scheduled dispatch virtual power
6		plant program in which customers that own or operate an energy
7		storage system that receive a rebate for the distributed
8		storage portion under paragraphs (1) and (2) of subsection (c)
9		are required to participate open an independent, statewide
10		investigation into the value of, and compensation for,
11		distributed energy resources. The Commission shall conduct the
12		investigation, but may arrange for experts or consultants
13		independent of the utilities and selected by the Commission to
14		assist with the investigation. The cost of the investigation
15		shall be shared by the utilities filing tariffs under
16		subsection (b) of this Section but may be recovered as an
17		expense through normal ratemaking procedures.
18		(1) The scheduled dispatch virtual power plant program
19		shall require an enrollment period of 5 years and require
20		each participating system to commit to dispatch each
21		weekday during the months of June, July, August, and
22		September from 4 p.m. to 6 p.m. for systems interconnected
23		behind the meter of a retail customer and from 4 p.m. to 7
24		p.m. for systems interconnected on the distribution system
25		of an electric utility and not behind the meter of a retail
26		customer. For stand-alone storage, commitments to dispatch

SB0025 Enrolled - 732 - LRB104 07069 BAB 17106 b
1		shall be voluntary. Upon petition by the applicable
2		electric utility or on its own motion, the Commission may
3		approve different dispatch schedules provided that
4		dispatch events do not exceed 80 days and shall not exceed
5		2 hours for systems interconnected behind the meter of a
6		retail customer or 3 hours for systems interconnected on
7		the distribution system of an electric utility and not
8		behind the meter of a retail customer. The Commission
9		shall ensure that the investigation includes, at minimum,
10		diverse sets of stakeholders; a review of best practices
11		in calculating the value of distributed energy resource
12		benefits; a review of the full value of the distributed
13		energy resources and the manner in which each component of
14		that value is or is not otherwise compensated; and
15		assessments of how the value of distributed energy
16		resources may evolve based on the present and future
17		technological capabilities of distributed energy resources
18		and based on present and future grid needs.
19		(2) The scheduled dispatch virtual power plant program
20		shall be open to all customer classes with eligible
21		distributed energy resources and shall measure performance
22		based on combined export of paired resources if the
23		eligible device is inverter-based renewables paired with
24		storage through at least December 31, 2030 and until the
25		Commission approves and the utility implements a tariff
26		under subsection (d) of Section 16-107.9 of this Act, at

SB0025 Enrolled - 733 - LRB104 07069 BAB 17106 b
1		which time such customers shall be transitioned to that
2		tariff in a manner prescribed in the tariff. The scheduled
3		dispatch virtual power plant program shall be required for
4		all community renewable generation projects paired with
5		distributed energy resources without regard to the
6		threshold date. The Commission's final order concluding
7		this investigation shall establish an annual process and
8		formula for the compensation of distributed generation and
9		energy storage systems, and an initial set of inputs for
10		that formula. The Commission's final order concluding this
11		investigation shall establish base rebates that compensate
12		distributed generation, community renewable generation
13		projects and energy storage systems for the system-wide
14		grid services that they provide. Those base rebate values
15		shall be consistent across the state, and shall not vary
16		by customer, customer class, customer location, or any
17		other variable. With respect to rebates for distributed
18		generation or community renewable generation projects,
19		that rebate shall not be lower than $250 per kilowatt of
20		nameplate generating capacity of the distributed
21		generation or community renewable generation project. The
22		Commission's final order concluding this proceeding shall
23		also direct the utilities to update the formula, on an
24		annual basis, with inputs derived from their integrated
25		grid plans developed pursuant to Section 16-105.17. The
26		base rebate shall be updated annually based on the annual

SB0025 Enrolled - 734 - LRB104 07069 BAB 17106 b
1		updates to the formula inputs, but, with respect to
2		rebates for distributed generation or community renewable
3		generation projects, shall be no lower than $250 per
4		kilowatt of nameplate generating capacity of the
5		distributed generation or community renewable generation
6		project.
7		(3) Compensation shall be set by the Commission but
8		shall not be less than $10 per kilowatt of average
9		dispatch during identified hours, paid to enrolled
10		customers or project owners at end of program year. For
11		distributed generation interconnected to an electric
12		utility's distribution system and not behind the meter of
13		a retail customer, dispatch to determine compensation
14		shall be measured at point of interconnection. For
15		distributed generation and storage interconnected behind
16		the meter of a retail customer, dispatch to determine
17		compensation shall be measured at the inverter connected
18		to the storage device. The Commission shall also
19		determine, as a part of its investigation under this
20		subsection, whether distributed energy resources can
21		provide any additive services. Those additive services may
22		include services that are provided through
23		utility-controlled responses to grid conditions. If the
24		Commission determines that distributed energy resources
25		can provide additive grid services, the Commission shall
26		determine the terms and conditions for the operation and

SB0025 Enrolled - 735 - LRB104 07069 BAB 17106 b
1		compensation of those services. That compensation shall be
2		above and beyond the base rebate that the distributed
3		energy generation, community renewable generation project
4		and energy storage system receives. Compensation for
5		additive services may vary by location, time, performance
6		characteristics, technology types, or other variables.
7		(4) No later than June 1, 2026, each public utility
8		shall file an initial scheduled dispatch virtual power
9		plant tariff. The Commission shall approve, or approve
10		with modifications, the initial scheduled dispatch virtual
11		power plant tariff for each utility not later than June
12		30, 2026. The Commission shall ensure that compensation
13		for distributed energy resources, including base rebates
14		and any payments for additive services, shall reflect all
15		reasonably known and measurable values of the distributed
16		generation over its full expected useful life.
17		Compensation for additive services shall reflect, but
18		shall not be limited to, any geographic, time-based,
19		performance-based, and other benefits of distributed
20		generation, as well as the present and future
21		technological capabilities of distributed energy resources
22		and present and future grid needs.
23		(5) The Commission, by its own motion or by petition
24		by an electric utility, may establish other additive
25		services programs in addition to the virtual power plant
26		program under Section 16-107.9. Nothing in this Section is

SB0025 Enrolled - 736 - LRB104 07069 BAB 17106 b
1		intended to preempt or delay the implementation of other
2		utility programs for devices that are not a part of the
3		scheduled dispatch virtual power plant program that the
4		Commission or utility may propose or require. The
5		Commission shall consider the electric utility's
6		integrated grid plan developed pursuant to Section
7		16-105.17 of this Act to help identify the value of
8		distributed energy resources for the purpose of
9		calculating the compensation described in this subsection.
10		(6) No later than December 31, 2028, the utilities
11		shall file with the Commission a report that includes
12		information on the following: (A) the number of
13		participants in the scheduled dispatch program; (B)
14		impacts to energy supply prices and wholesale market
15		activities; (C) impacts on distribution system investments
16		and planning; and (D) any potential pathways by which the
17		virtual power plan program described in Section 16-107.9
18		may be designed to capture wholesale market value through
19		participation in the wholesale market and apply that
20		wholesale market revenue to reduce utility distribution or
21		electric supply rates for customers. The Commission shall
22		determine additional compensation for distributed energy
23		resources that creates savings and value on the
24		distribution system by being co-located or in close
25		proximity to electric vehicle charging infrastructure in
26		use by medium-duty and heavy-duty vehicles, primarily

SB0025 Enrolled - 737 - LRB104 07069 BAB 17106 b
1		serving environmental justice communities, as outlined in
2		the utility integrated grid planning process under Section
3		16-105.17 of this Act.
4		No later than 60 days after the Commission enters its
5		final order under this subsection (e), each utility shall file
6		its updated tariff or tariffs in compliance with the order,
7		including new tariffs for the recovery of costs incurred under
8		this subsection (e) that shall provide for volumetric-based
9		cost recovery, and the Commission shall approve, or approve
10		with modification, the tariff or tariffs within 240 days after
11		the utility's filing.
12		(f) Notwithstanding any provision of this Act to the
13		contrary, the owner or operator of a community renewable
14		generation project as defined in Section 1-10 of the Illinois
15		Power Agency Act whether or not a paired energy storage system
16		or the owner or operator of an energy storage system that is
17		eligible for net metering under subsection (l-10) of Section
18		16-107.5 shall also be eligible to apply for the rebate
19		described in this Section. The owner or operator of the
20		community renewable generation project whether or not a paired
21		energy storage system or the owner or operator of an energy
22		storage system that is eligible for net metering under
23		subsection (l-10) of Section 16-107.5 may apply for a rebate
24		only if the owner or operator, or previous owner or operator,
25		of the community renewable generation project whether or not a
26		paired energy storage system or the owner or operator of an

SB0025 Enrolled - 738 - LRB104 07069 BAB 17106 b
1		energy storage system that is eligible for net metering under
2		subsection (l-10) of Section 16-107.5 has not already
3		submitted an application, and, regardless of whether the
4		subscriber is a residential or non-residential customer, may
5		be allowed the amount identified in paragraph (1) of
6		subsection (c) applicable on the date that the application is
7		submitted.
8		(g) The owner of a distributed storage system, whether or
9		not paired with distributed generation, the distributed
10		generation or community renewable generation project may apply
11		for the rebate or rebates approved under this Section at the
12		time of execution of an interconnection agreement with the
13		distribution utility and shall receive the value available at
14		that time of execution of the interconnection agreement,
15		provided the project reaches mechanical completion within 24
16		months after execution of the interconnection agreement. If
17		the project has not reached mechanical completion within 24
18		months after execution, the owner may reapply for the rebate
19		or rebates approved under this Section available at the time
20		of application and shall receive the value available at the
21		time of application. The utility shall issue the rebate no
22		later than 60 days after the project is energized. In the event
23		the application is incomplete or the utility is otherwise
24		unable to calculate the payment based on the information
25		provided by the owner, the utility shall issue the payment no
26		later than 60 days after the application is complete or all

SB0025 Enrolled - 739 - LRB104 07069 BAB 17106 b
1		requested information is received.
2		(h) An electric utility shall recover from its retail
3		customers all of the costs of the rebates made under a tariff
4		or tariffs approved under subsection (d) of this Section,
5		including, but not limited to, the value of the rebates and all
6		costs incurred by the utility to comply with and implement
7		subsections (b), (b-5), and (c), and (e) of this Section, but
8		not including costs incurred by the utility to comply with and
9		implement subsection (e) of this Section, consistent with the
10		following provisions:
11		(1) The utility shall defer the full amount of its
12		costs as a regulatory asset. The total costs deferred as a
13		regulatory asset shall be amortized over a 15-year period.
14		The unamortized balance shall be recognized as of December
15		31 for a given year. The utility shall also earn a return
16		on the total of the unamortized balance of the regulatory
17		assets, less any deferred taxes related to the unamortized
18		balance, at an annual rate equal to the utility's weighted
19		average cost of capital that includes, based on a year-end
20		capital structure, the utility's actual cost of debt for
21		the applicable calendar year and a cost of equity, which
22		shall be equal to the baseline cost of equity approved by
23		the Commission for the utility's electric distribution
24		rates case effective during the applicable year, whether
25		those rates are set pursuant to Section 9-201,
26		subparagraph (B) of paragraph (3) of subsection (d) of

SB0025 Enrolled - 740 - LRB104 07069 BAB 17106 b
1		Section 16-108.18, or any successor electric distribution
2		ratemaking paradigm calculated as the sum of (i) the
3		average for the applicable calendar year of the monthly
4		average yields of 30-year U.S. Treasury bonds published by
5		the Board of Governors of the Federal Reserve System in
6		its weekly H.15 Statistical Release or successor
7		publication; and (ii) 580 basis points, including a
8		revenue conversion factor calculated to recover or refund
9		all additional income taxes that may be payable or
10		receivable as a result of that return.
11		When an electric utility creates a regulatory asset
12		under the provisions of this paragraph (1) of subsection
13		(h), the costs are recovered over a period during which
14		customers also receive a benefit, which is in the public
15		interest. Accordingly, it is the intent of the General
16		Assembly that an electric utility that elects to create a
17		regulatory asset under the provisions of this paragraph
18		(1) shall recover all of the associated costs, including,
19		but not limited to, its cost of capital as set forth in
20		this paragraph (1). After the Commission has approved the
21		prudence and reasonableness of the costs that comprise the
22		regulatory asset, the electric utility shall be permitted
23		to recover all such costs, and the value and
24		recoverability through rates of the associated regulatory
25		asset shall not be limited, altered, impaired, or reduced.
26		To enable the financing of the incremental capital

SB0025 Enrolled - 741 - LRB104 07069 BAB 17106 b
1		expenditures, including regulatory assets, for electric
2		utilities that serve less than 3,000,000 retail customers
3		but more than 500,000 retail customers in the State, the
4		utility's actual year-end capital structure that includes
5		a common equity ratio, excluding goodwill, of up to and
6		including 50% of the total capital structure shall be
7		deemed reasonable and used to set rates.
8		(2) The utility, at its election, may recover all of
9		the costs as part of a filing for a general increase in
10		rates under Article IX of this Act, as part of an annual
11		filing to update a performance-based formula rate under
12		Section 16-108.18 subsection (d) of Section 16-108.5 of
13		this Act, or through an automatic adjustment clause
14		tariff, provided that nothing in this paragraph (2)
15		permits the double recovery of such costs from customers.
16		If the utility elects to recover the costs it incurs under
17		subsections (b), (b-5), and (c), and (e) through an
18		automatic adjustment clause tariff, the utility may file
19		its proposed tariff together with the tariff it files
20		under subsection (b) of this Section or at a later time.
21		The proposed tariff shall provide for an annual
22		reconciliation, less any deferred taxes related to the
23		reconciliation, with interest at an annual rate of return
24		equal to the utility's weighted average cost of capital as
25		calculated under paragraph (1) of this subsection (h),
26		including a revenue conversion factor calculated to

SB0025 Enrolled - 742 - LRB104 07069 BAB 17106 b
1		recover or refund all additional income taxes that may be
2		payable or receivable as a result of that return, of the
3		revenue requirement reflected in rates for each calendar
4		year, beginning with the calendar year in which the
5		utility files its automatic adjustment clause tariff under
6		this subsection (h), with what the revenue requirement
7		would have been had the actual cost information for the
8		applicable calendar year been available at the filing
9		date. The Commission shall review the proposed tariff and
10		may make changes to the tariff that are consistent with
11		this Section and with the Commission's authority under
12		Article IX of this Act, subject to notice and hearing.
13		Following notice and hearing, the Commission shall issue
14		an order approving, or approving with modification, such
15		tariff no later than 240 days after the utility files its
16		tariff.
17		(i) (Blank). An electric utility shall recover from its
18		retail customers, on a volumetric basis, all of the costs of
19		the rebates made under a tariff or tariffs placed into effect
20		under subsection (e) of this Section, including, but not
21		limited to, the value of the rebates and all costs incurred by
22		the utility to comply with and implement subsection (e) of
23		this Section, consistent with the following provisions:
24		(1) The utility may defer a portion of its costs as a
25		regulatory asset. The Commission shall determine the
26		portion that may be appropriately deferred as a regulatory

SB0025 Enrolled - 743 - LRB104 07069 BAB 17106 b
1		asset. Factors that the Commission shall consider in
2		determining the portion of costs that shall be deferred as
3		a regulatory asset include, but are not limited to: (i)
4		whether and the extent to which a cost effectively
5		deferred or avoided other distribution system operating
6		costs or capital expenditures; (ii) the extent to which a
7		cost provides environmental benefits; (iii) the extent to
8		which a cost improves system reliability or resilience;
9		(iv) the electric utility's distribution system plan
10		developed pursuant to Section 16-105.17 of this Act; (v)
11		the extent to which a cost advances equity principles; and
12		(vi) such other factors as the Commission deems
13		appropriate. The remainder of costs shall be deemed an
14		operating expense and shall be recoverable if found
15		prudent and reasonable by the Commission.
16		The total costs deferred as a regulatory asset shall
17		be amortized over a 15-year period. The unamortized
18		balance shall be recognized as of December 31 for a given
19		year. The utility shall also earn a return on the total of
20		the unamortized balance of the regulatory assets, less any
21		deferred taxes related to the unamortized balance, at an
22		annual rate equal to the utility's weighted average cost
23		of capital that includes, based on a year-end capital
24		structure, the utility's actual cost of debt for the
25		applicable calendar year and a cost of equity, which shall
26		be calculated as the sum of: (I) the average for the

SB0025 Enrolled - 744 - LRB104 07069 BAB 17106 b
1		applicable calendar year of the monthly average yields of
2		30-year U.S. Treasury bonds published by the Board of
3		Governors of the Federal Reserve System in its weekly H.15
4		Statistical Release or successor publication; and (II) 580
5		basis points, including a revenue conversion factor
6		calculated to recover or refund all additional income
7		taxes that may be payable or receivable as a result of that
8		return.
9		(2) The utility may recover all of the costs through
10		an automatic adjustment clause tariff, on a volumetric
11		basis. The utility may file its proposed cost-recovery
12		tariff together with the tariff it files under subsection
13		(e) of this Section or at a later time. The proposed tariff
14		shall provide for an annual reconciliation, less any
15		deferred taxes related to the reconciliation, with
16		interest at an annual rate of return equal to the
17		utility's weighted average cost of capital as calculated
18		under paragraph (1) of this subsection (i), 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, of the revenue
22		requirement reflected in rates for each calendar year,
23		beginning with the calendar year in which the utility
24		files its automatic adjustment clause tariff under this
25		subsection (i), with what the revenue requirement would
26		have been had the actual cost information for the

SB0025 Enrolled - 745 - LRB104 07069 BAB 17106 b
1		applicable calendar year been available at the filing
2		date. The Commission shall review the proposed tariff and
3		may make changes to the tariff that are consistent with
4		this Section and with the Commission's authority under
5		Article IX of this Act, subject to notice and hearing.
6		Following notice and hearing, the Commission shall issue
7		an order approving, or approving with modification, such
8		tariff no later than 240 days after the utility files its
9		tariff.
10		(j) No later than 90 days after the Commission enters an
11		order, or order on rehearing, whichever is later, approving an
12		electric utility's proposed tariff under this Section, the
13		electric utility shall provide notice of the availability of
14		rebates under this Section.
15		(k) No later than January 1, 2030, the utilities shall
16		file with the Commission a report that includes:
17		(1) the number and geographic distribution of
18		participants receiving rebates pursuant to this Section;
19		(2) impacts to energy supply prices and wholesale
20		market activities;
21		(3) impacts on distribution system investments and
22		planning; and
23		(4) any other values deemed relevant by the
24		Commission.
25		(l) Upon petition by the applicable electric utility or on
26		its own motion, the Commission may adjust rebate levels for

SB0025 Enrolled - 746 - LRB104 07069 BAB 17106 b
1		new customers and make other appropriate changes to the rebate
2		program in a manner that is consistent with the State's clean
3		energy goals and the public interest.
4		(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22;
5		103-1066, eff. 2-20-25.)
6		(220 ILCS 5/16-107.8 new)
7		Sec. 16-107.8. Time-of-use pricing.
8		(a) The General Assembly finds that market-based
9		time-of-use rates and pricing plans can reduce costs and help
10		the State achieve its energy policy goals by improving load
11		shape, encouraging energy conservation, and shifting usage
12		away from periods where fossil fuels are used. By providing
13		consumers information relating the costs of service to the
14		time of energy usage, time-of-use rates can help consumers
15		reduce energy bills by using electricity when it is less
16		costly.
17		(b) An electric utility shall offer at least one
18		market-based rate option for eligible retail customers,
19		including, but not limited to, customers participating in net
20		electricity metering under the terms of Section 16-107.5, who
21		choose to take power and energy supply service from the
22		utility. The provisions of Section 16-107.5 notwithstanding,
23		energy credits for net-metering customers shall be valued at
24		the same price per kilowatt-hour as the price per
25		kilowatt-hour that the electric service provider would charge

SB0025 Enrolled - 747 - LRB104 07069 BAB 17106 b
1		for kilowatt-hour energy sales during the same hourly
2		time-of-use period. The utility shall file its time-of-use
3		rate tariff no later than 120 days after the effective date of
4		this amendatory Act of the 104th General Assembly. The tariff
5		or tariffs shall be subject to the following requirements:
6		(1) If more than one tariff is proposed, at least one
7		tariff shall include at least the following 3 time blocks:
8		(A) a peak time block of consecutive hours best
9		reflecting the average consecutive highest system
10		power and energy use per hour in a calendar day;
11		(B) an off-peak time block, which reflects the
12		next highest system power and energy demands in a
13		calendar day; and
14		(C) a super-off-peak time block, defined as all
15		other hours in a calendar day.
16		Time blocks shall reflect the hour and weekday for
17		which the costs of services outlined in paragraphs (2)
18		and (3) of this subsection (b) are charged.
19		(2) The tariff or tariffs shall describe the
20		methodology for determining the prices for each time block
21		using the applicable average zonal and capacity prices of
22		the PJM Interconnection, LLC (PJM) and the Midcontinent
23		Independent System Operator (MISO) and describe the manner
24		in which customers who elect time-of-use pricing will be
25		provided with the time blocks, associated block pricing,
26		and day-ahead energy prices. Costs for electric capacity

SB0025 Enrolled - 748 - LRB104 07069 BAB 17106 b
1		shall be determined in a manner that recovers the capacity
2		obligation costs incurred by the electric utility.
3		(3) The time-of-use rate shall include the costs of
4		transmission services and the charges for network
5		integration transmission service, transmission
6		enhancement, and locational reliability, as these terms
7		are defined in the PJM and MISO Open Access Transmission
8		Tariffs and manuals. If the Open Access Transmission
9		Tariff or the manuals subsequently rename those terms, the
10		services reflected under those terms shall continue to be
11		included in the time-of-use rate described in this
12		paragraph (3).
13		(4) Adjustments to the charges set by the tariff may
14		be made on a monthly basis and adjustments to the time
15		blocks may be made on an annual basis. A utility shall
16		submit to the Commission, through a supplemental
17		information sheet, a tariff schedule. Customers shall be
18		provided at least 2 weeks advance notice of any changes to
19		charges or time blocks.
20		(5) A purchased energy adjustment shall be calculated
21		to fully recover costs to supply power and energy. A
22		utility shall procure power and energy in the applicable
23		day-ahead market.
24		(c) The Commission shall approve or approve with
25		modifications the tariff or tariffs after notice and hearing.
26		A proceeding under this subsection (c) may not exceed 240 days

SB0025 Enrolled - 749 - LRB104 07069 BAB 17106 b
1		in length.
2		(d) An electric utility shall submit an annual report to
3		the Commission no later than April 1 of each year that
4		describes the operation and results of the rate option,
5		including information concerning the number and types of
6		customers using the rate option, changes in customers' energy
7		use patterns, an assessment of the value of the rate option to
8		both participants and nonparticipants, and recommendations
9		concerning modification of the rate option and the tariff or
10		tariffs filed under this Section. The report shall be made
11		available to the public on the Commission's website.
12		(e) Once a tariff or tariffs has been in effect, the
13		Commission may, upon complaint, petition, or its own
14		initiative, open a proceeding to investigate whether changes
15		or modifications, consistent with the requirements of this
16		Section, to the tariff or tariffs, rate option administration,
17		or any other rate option element is necessary to achieve the
18		goals described in subsection (a). Such a proceeding may not
19		last more than 180 days from the date upon which the
20		investigation was opened.
21		(f) An electric utility shall be entitled to recover
22		prudent and reasonable costs incurred in complying with this
23		Section from its eligible retail customers.
24		(g) An electric utility's tariff or tariffs filed under
25		this Section shall be subject to the provisions of Article IX
26		as long as such provisions do not conflict with this Section.

SB0025 Enrolled - 750 - LRB104 07069 BAB 17106 b
1		(h) This Section does not apply to an electric utility
2		that provides service to 100,000 or fewer customers.
3		(220 ILCS 5/16-107.9 new)
4		Sec. 16-107.9. Virtual power plant program.
5		(a) As used in this Section:
6		"Aggregator" means a third-party entity that participates
7		in the program, other than the electric utility or its
8		affiliate, that (i) represents and aggregates the load of
9		participating customers who collectively have the ability to
10		deploy 100 kilowatts or more of deployment of eligible devices
11		and (ii) is responsible for performance of the aggregation in
12		the program.
13		"Battery" means a behind-the-meter energy storage device
14		and associated equipment that operate together to fulfill
15		program requirements.
16		"Commission" means the Illinois Commerce Commission.
17		"Customer" means an active electric service account holder
18		of a utility.
19		"Direct participant" means a customer that enrolls in the
20		program directly with the utility, rather than participating
21		in the program through an aggregator.
22		"Distributed energy resource" has the meaning set forth in
23		Section 16-107.6.
24		"Distributed energy resources management system" means a
25		platform that may be used by distribution system operators or

SB0025 Enrolled - 751 - LRB104 07069 BAB 17106 b
1		utilities to integrate grid resources, such as distributed
2		energy resources, into system operations.
3		"Eligible device" means a customer or third party-owned
4		distributed energy resource that satisfies the requirements
5		for participation in the program as specified in the relevant
6		program rider. "Eligible device" also means any device that
7		can be controlled to respond to pricing, provide services,
8		including decrease peak electricity demand or shift demand
9		from peak to off-peak periods, or inject power to the grid.
10		"Eligible device" includes, but is not limited to,
11		behind-the-meter energy storage systems, smart thermostats,
12		electric vehicle batteries, including fleets, and distributed
13		renewable energy devices paired with one or more energy
14		storage systems.
15		"Emergency event" means an event called by the utility
16		with fewer than 24 hours notice.
17		"Energy storage system" has the meaning set forth in
18		subsection (a) of Section 16-107.6.
19		"Enrolled customer" means a customer that participates in
20		the program through either an aggregator or as a direct
21		participant.
22		"Enrolled device" means an enrolled customer's eligible
23		device, as specified in the relevant tariff.
24		"Enterprise distributed energy resources management
25		system" means a platform operated by the electric utility that
26		interfaces with a grid-edge distributed energy resources

SB0025 Enrolled - 752 - LRB104 07069 BAB 17106 b
1		management system to integrate distributed energy resources
2		into utility electric system operations.
3		"Grid-edge distributed energy resources management system"
4		means a platform owned by a party other than the electric
5		utility that may be used to integrate distributed energy
6		resources.
7		"Grid event" means a grid condition for which the utility
8		schedules or remotely dispatches enrolled devices to respond
9		to, as specified in the grid service opportunities for each
10		tariff.
11		"Grid service" means a capacity, energy, or ancillary
12		service that supports grid operations.
13		"Participating customer" means an aggregator or a direct
14		retail customer, as defined in Section 16-102, with one or
15		more eligible devices.
16		"Performance payment" means a payment made to the
17		participant based on the performance of an enrolled device
18		providing a grid service during a grid event.
19		"Performance payment rate" means the compensation rate
20		paid to participants for providing a particular grid service
21		during a grid event.
22		"Smart inverter" has the meaning set forth in subsection
23		(a) of Section 16-107.6.
24		"Upfront payment" means a one-time payment made at the
25		time of enrollment.
26		"Virtual power plant" means an aggregation of

SB0025 Enrolled - 753 - LRB104 07069 BAB 17106 b
1		behind-the-meter distributed energy resources operated in
2		coordination to provide one or more grid services.
3		(b) The General Assembly finds that:
4		(1) virtual power plants are dynamic load management
5		and energy supply resources that can support grid
6		operations, reduce ratepayer costs, and achieve other
7		important public policy goals;
8		(2) virtual power plants can reduce demand for grid
9		supplied electricity during peak periods, shift
10		electricity consumption out of peak periods, make
11		renewable energy generated during off-peak periods
12		available for use during peak periods, supply energy to
13		the grid at desired times, provide frequency regulation,
14		voltage support, and other ancillary services, reduce
15		strain on the distribution system, manage localized peaks,
16		improve system resiliency and reliability, and provide
17		other grid services;
18		(3) virtual power plants can facilitate and optimize
19		the utilization of electrical generation from wind and
20		solar energy to help utilities increase hosting capacity
21		and integrate more renewable energy resources;
22		(4) virtual power plants can reduce costs to
23		ratepayers by utilizing customer-sited resources to
24		provide grid services, avoiding or reducing reliance on
25		fossil-fuel fired peaker plants, avoiding or deferring the
26		need to construct new and more costly grid scale

SB0025 Enrolled - 754 - LRB104 07069 BAB 17106 b
1		resources, optimizing the use of existing assets, and
2		avoiding or deferring distribution and transmission system
3		upgrades and other grid investments;
4		(5) virtual power plants can promote equity by
5		reducing costs for all ratepayers, expanding access to
6		distributed energy resources among low-income and
7		moderate-income customers through improved distributed
8		energy resource finance ability, and providing other
9		important co-benefits, including reduction in emissions of
10		greenhouse gases and other pollutants, especially in
11		environmental justice and other disadvantaged communities
12		that host fossil fuel generation plants;
13		(6) the United States Department of Energy estimates
14		that the United States could deploy 80 to 160 gigawatts of
15		virtual power plants by 2030, a tripling of current
16		levels, to support the rapid electrification of vehicles
17		and homes and provide on the order of $10,000,000,000 in
18		ratepayer savings annually. The deployment of virtual
19		power plants can provide energy cost savings and other
20		benefits to the people of Illinois;
21		(7) there are significant barriers to deployment and
22		operation of virtual power plants, including the need for
23		statutory and regulatory guidance and support, greater
24		consistency in virtual power plant programs across
25		regulatory jurisdictions, and for utility commitments to
26		incorporate the use of virtual power plants into system

SB0025 Enrolled - 755 - LRB104 07069 BAB 17106 b
1		operations and long-term resource planning;
2		(8) it is in the public interest to advance customer
3		choice and leverage the expertise of private, non-utility
4		entities to advance innovation and implement
5		cost-effective clean energy solutions; and
6		(9) the policy of Illinois shall be to maximize the
7		use of virtual power plants comprised of customer-owned
8		and third party-owned distributed energy resources to
9		deliver system services and other benefits through utility
10		administered virtual power plant programs in accordance
11		with the provisions of this amendatory Act of the 104th
12		General Assembly.
13		(c) No later than December 31, 2028, the Commission shall
14		approve at least one virtual power plant tariff for each
15		electric utility serving more than 300,000 customers in the
16		State as of January 1, 2023. Each utility shall file a tariff
17		or tariffs for approval no later than December 31, 2027 to
18		allow retail customers in the electric utility's service areas
19		to participate in a virtual power plant program proposal
20		consistent with the provisions of this Section. The Commission
21		shall provide opportunities for stakeholders to provide input
22		on the virtual power plant programs proposed for
23		implementation by each utility, which the Commission shall
24		take into consideration in its review of each utility's
25		filing. No later than one year after the utility's filing, the
26		Commission shall approve or modify and approve each utility's

SB0025 Enrolled - 756 - LRB104 07069 BAB 17106 b
1		virtual power plant program proposal for immediate
2		implementation by the utility.
3		(d) The virtual power plant program filed under subsection
4		(c) shall be developed for implementation through a tariff
5		offering with standard terms and conditions for participation.
6		The virtual power plant program tariff shall allow for
7		customers with battery storage, non-battery storage and
8		electric vehicle technologies to enroll the devices in the
9		program through aggregators or directly with the utility. The
10		virtual power plant program tariff shall:
11		(1) provide a mechanism to incorporate existing
12		programs, such as smart thermostat demand-response or
13		electric vehicle charging programs currently offered by
14		the utility, under the virtual power plant program
15		framework;
16		(2) provide grid services opportunities for each
17		eligible technology that customers and aggregators may
18		provide, which shall include, at minimum, reducing the
19		utility's applicable capacity and transmission obligations
20		and capturing daily wholesale energy arbitrage
21		opportunities through provision of grid services;
22		(3) provide additional functions and grid service
23		opportunities that the Commission determines are
24		supportive of efficient planning and operation of the
25		electrical grid, including:
26		(A) minimizing the use of fossil fuels at peak

SB0025 Enrolled - 757 - LRB104 07069 BAB 17106 b
1		times;
2		(B) local peak demand reductions;
3		(C) locational value;
4		(D) the avoidance or deferral of local
5		transmission or distribution upgrades or capacity
6		expansion;
7		(E) voltage support and other ancillary services;
8		and
9		(F) emergency grid services;
10		(4) provide operational parameters, which shall
11		include, at a minimum:
12		(A) minimum and maximum numbers of grid events for
13		which the utility may require dispatch from the
14		enrolled distributed energy resources;
15		(B) months of the year that grid events may occur;
16		(C) days of the week that grid events may occur;
17		(D) times of day that grid events may occur;
18		(E) maximum duration of grid events; and
19		(F) minimum day-ahead advance notification
20		requirement of grid events, except for emergency
21		events, as applicable;
22		(5) include provisions for aggregators to participate
23		in the virtual power plant program, participate in the
24		utility's distributed energy resource management system as
25		available, automatically enroll and manage their
26		customers' participation, receive dispatch signals and

SB0025 Enrolled - 758 - LRB104 07069 BAB 17106 b
1		other communications from the utility, deliver performance
2		measurement and verification data to the utility, and
3		receive virtual power plant program payments directly from
4		the utility;
5		(6) include provisions that provide a standardized
6		process for any eligible aggregator to enroll in the
7		program and authorize the eligible aggregators to manage
8		individual customer device participation without
9		additional authorizations from the utility;
10		(7) include provisions that allow a participating
11		customer with multiple eligible devices to enroll the
12		technologies either directly without an aggregator or
13		through one or more aggregators in applicable programs
14		under the tariff approved under this Section, provided
15		that no particular device is accounted for more than once;
16		(8) include provisions for direct participant
17		customers to participate with the utility's distributed
18		energy resource management system as available, receive
19		dispatch signals and other communications from the
20		utility, deliver performance measurement and verification
21		data to the utility, and receive virtual power plant
22		program payments directly from the utility. Any provisions
23		implementing this subpart that necessitate the
24		installation of equipment to enable direct participation
25		via the utility shall apply to customers who elect to
26		participate as a direct participant and shall not be

SB0025 Enrolled - 759 - LRB104 07069 BAB 17106 b
1		required of customers who participate via an aggregator or
2		to customers who do not participate in the virtual power
3		plant program;
4		(9) provide for measurement and verification of
5		battery non-battery, and electric vehicle technologies
6		performance directly at the device without the requirement
7		for the installation of an additional meter;
8		(10) include upfront payment or performance payment
9		compensation mechanisms for the peak reduction service, as
10		well as for non-battery and electric vehicle technologies
11		as the Commission deems appropriate. The performance
12		payment shall be based on the average capacity provided
13		during grid events. The Commission shall approve
14		additional compensation mechanisms as it determines
15		appropriate for other grid services provided under the
16		battery, non-battery and electric vehicle riders. The
17		virtual power plant program shall not assess penalties for
18		non-performance; provided, however, that the Commission
19		may approve reasonable mechanisms to disenroll customers
20		for continued non-performance;
21		(11) enable low-to-moderate income customers,
22		community-driven community solar projects, and customers
23		whose electric service has not been declared competitive
24		pursuant to Section 16-113 as of July 1, 2011 located in
25		equity investment eligible investment communities to
26		receive a higher upfront enrollment payment. The

SB0025 Enrolled - 760 - LRB104 07069 BAB 17106 b
1		Commission shall coordinate with State energy officials
2		and departments to make funding from federal programs and
3		such other sources as may be available for use in
4		providing higher upfront payments to customers classes as
5		may be approved by the Commission in accordance with this
6		subsection;
7		(12) provide that the performance payment rate
8		applicable at the time of enrollment shall be for 5 years,
9		after which time the participant may reenroll at the then
10		applicable performance payment rate for an additional
11		5-year term;
12		(13) provide for a transition of customers from the
13		scheduled dispatch program described in Section 16-107.6
14		to the virtual power plant program; and
15		(14) allow enrolled customers to participate in other
16		applicable interconnection tariffs and grid service
17		programs outside the virtual power plant program, so long
18		as it does not result in double-counting of benefits for
19		the same grid services.
20		(e) The Commission may adopt other reasonable requirements
21		for participation consistent with this subsection, provided
22		that collateral from an aggregator shall not be required for
23		participation.
24		(f) The utility may contract with a third party-owned
25		distributed energy resource management system provider to
26		assist with program implementation; however, implementation

SB0025 Enrolled - 761 - LRB104 07069 BAB 17106 b
1		shall not be delayed due to the lack of utility-owned
2		distributed energy resource management system capabilities or
3		third party-owned distributed energy resource management
4		system capabilities.
5		(g) The utility shall not send or receive dispatch signals
6		directly to or from any participating customer represented by
7		an aggregator for an event under the virtual power plant
8		program described in this Section.
9		(h) Participating aggregators shall have capabilities to
10		receive event signals from utilities or utility-contracted
11		distributed energy resources management system providers.
12		(i) Utilities shall recover reasonably and prudently
13		incurred costs to facilitate the virtual power plant program
14		approved under subsection (c), including, but not limited to,
15		distributed energy resource management systems provider and
16		other service contract costs, operations and maintenance
17		expenses, information technology costs, and other costs,
18		expenses, and investments that the Commission finds necessary
19		and prudent for the development and implementation of the
20		program. The utility shall recover the cost of virtual power
21		plant program upfront payments and performance payments and
22		such other payments made to participants through the tariff
23		filed pursuant to subsection (h) of Section 16-107.6.
24		(j) No later than January 31 of each year, each utility
25		shall file an annual report that includes, but is not limited
26		to:

SB0025 Enrolled - 762 - LRB104 07069 BAB 17106 b
1		(1) the total capacity enrolled in each program rider
2		developed in accordance with the requirements of Section,
3		broken down by technology type, customer class, and
4		aggregator and direct participant status for each grid
5		service opportunity offered in the prior calendar year;
6		(2) recommendations to increase participation in the
7		virtual power plant program; and
8		(3) any other information that the Commission may
9		require.
10		(k) Each utility shall amend existing tariffs and
11		procedures that limit the ability of customers to participate
12		in providing grid services under the program, such as
13		limitations on charging energy storage devices with grid
14		energy or exporting energy to the grid from battery discharge.
15		(l) The tariffs approved by the Commission shall not
16		reflect any additional charges, fees, or insurance
17		requirements imposed on those owning or operating
18		demand-response technologies beyond those imposed on similarly
19		situated customers that do not own or operate demand-response
20		technologies.
21		(m) As a condition of participating in the programs
22		described in this Section, prior to enrollment of a customer
23		by an aggregator, the aggregator shall disclose the following:
24		(1) the payments, expressed as an amount or a formula,
25		to be provided to the customer;
26		(2) between the aggregator and customer, who is

SB0025 Enrolled - 763 - LRB104 07069 BAB 17106 b
1		responsible for paying penalties or fees; and
2		(3) between the aggregator and customer, who is
3		responsible for posting collateral, if required.
4		Any tariff authorized by this Section shall incorporate
5		the requirements under this subsection and shall require the
6		electric utility to establish a complaint and Commission
7		notification process and, on order of the Commission, suspend
8		any aggregator repeatedly or egregiously violating such
9		requirements.
10		(220 ILCS 5/16-108)
11		Sec. 16-108. Recovery of costs associated with the
12		provision of delivery and other services.
13		(a) An electric utility shall file a delivery services
14		tariff with the Commission at least 210 days prior to the date
15		that it is required to begin offering such services pursuant
16		to this Act. An electric utility shall provide the components
17		of delivery services that are subject to the jurisdiction of
18		the Federal Energy Regulatory Commission at the same prices,
19		terms and conditions set forth in its applicable tariff as
20		approved or allowed into effect by that Commission. The
21		Commission shall otherwise have the authority pursuant to
22		Article IX to review, approve, and modify the prices, terms
23		and conditions of those components of delivery services not
24		subject to the jurisdiction of the Federal Energy Regulatory
25		Commission, including the authority to determine the extent to

SB0025 Enrolled - 764 - LRB104 07069 BAB 17106 b
1		which such delivery services should be offered on an unbundled
2		basis. In making any such determination the Commission shall
3		consider, at a minimum, the effect of additional unbundling on
4		(i) the objective of just and reasonable rates, (ii) electric
5		utility employees, and (iii) the development of competitive
6		markets for electric energy services in Illinois.
7		(b) The Commission shall enter an order approving, or
8		approving as modified, the delivery services tariff no later
9		than 30 days prior to the date on which the electric utility
10		must commence offering such services. The Commission may
11		subsequently modify such tariff pursuant to this Act.
12		(c) The electric utility's tariffs shall define the
13		classes of its customers for purposes of delivery services
14		charges. Delivery services shall be priced and made available
15		to all retail customers electing delivery services in each
16		such class on a nondiscriminatory basis regardless of whether
17		the retail customer chooses the electric utility, an affiliate
18		of the electric utility, or another entity as its supplier of
19		electric power and energy. Charges for delivery services shall
20		be cost based, and shall allow the electric utility to recover
21		the costs of providing delivery services through its charges
22		to its delivery service customers that use the facilities and
23		services associated with such costs. Such costs shall include
24		the costs of owning, operating and maintaining transmission
25		and distribution facilities. The Commission shall also be
26		authorized to consider whether, and if so to what extent, the

SB0025 Enrolled - 765 - LRB104 07069 BAB 17106 b
1		following costs are appropriately included in the electric
2		utility's delivery services rates: (i) the costs of that
3		portion of generation facilities used for the production and
4		absorption of reactive power in order that retail customers
5		located in the electric utility's service area can receive
6		electric power and energy from suppliers other than the
7		electric utility, and (ii) the costs associated with the use
8		and redispatch of generation facilities to mitigate
9		constraints on the transmission or distribution system in
10		order that retail customers located in the electric utility's
11		service area can receive electric power and energy from
12		suppliers other than the electric utility. Nothing in this
13		subsection shall be construed as directing the Commission to
14		allocate any of the costs described in (i) or (ii) that are
15		found to be appropriately included in the electric utility's
16		delivery services rates to any particular customer group or
17		geographic area in setting delivery services rates.
18		(d) The Commission shall establish charges, terms and
19		conditions for delivery services that are just and reasonable
20		and shall take into account customer impacts when establishing
21		such charges. In establishing charges, terms and conditions
22		for delivery services, the Commission shall take into account
23		voltage level differences. A retail customer shall have the
24		option to request to purchase electric service at any delivery
25		service voltage reasonably and technically feasible from the
26		electric facilities serving that customer's premises provided

SB0025 Enrolled - 766 - LRB104 07069 BAB 17106 b
1		that there are no significant adverse impacts upon system
2		reliability or system efficiency. A retail customer shall also
3		have the option to request to purchase electric service at any
4		point of delivery that is reasonably and technically feasible
5		provided that there are no significant adverse impacts on
6		system reliability or efficiency. Such requests shall not be
7		unreasonably denied.
8		(e) Electric utilities shall recover the costs of
9		installing, operating or maintaining facilities for the
10		particular benefit of one or more delivery services customers,
11		including without limitation any costs incurred in complying
12		with a customer's request to be served at a different voltage
13		level, directly from the retail customer or customers for
14		whose benefit the costs were incurred, to the extent such
15		costs are not recovered through the charges referred to in
16		subsections (c) and (d) of this Section.
17		(f) An electric utility shall be entitled but not required
18		to implement transition charges in conjunction with the
19		offering of delivery services pursuant to Section 16-104. If
20		an electric utility implements transition charges, it shall
21		implement such charges for all delivery services customers and
22		for all customers described in subsection (h), but shall not
23		implement transition charges for power and energy that a
24		retail customer takes from cogeneration or self-generation
25		facilities located on that retail customer's premises, if such
26		facilities meet the following criteria:

SB0025 Enrolled - 767 - LRB104 07069 BAB 17106 b
1		(i) the cogeneration or self-generation facilities
2		serve a single retail customer and are located on that
3		retail customer's premises (for purposes of this
4		subparagraph and subparagraph (ii), an industrial or
5		manufacturing retail customer and a third party contractor
6		that is served by such industrial or manufacturing
7		customer through such retail customer's own electrical
8		distribution facilities under the circumstances described
9		in subsection (vi) of the definition of "alternative
10		retail electric supplier" set forth in Section 16-102,
11		shall be considered a single retail customer);
12		(ii) the cogeneration or self-generation facilities
13		either (A) are sized pursuant to generally accepted
14		engineering standards for the retail customer's electrical
15		load at that premises (taking into account standby or
16		other reliability considerations related to that retail
17		customer's operations at that site) or (B) if the facility
18		is a cogeneration facility located on the retail
19		customer's premises, the retail customer is the thermal
20		host for that facility and the facility has been designed
21		to meet that retail customer's thermal energy requirements
22		resulting in electrical output beyond that retail
23		customer's electrical demand at that premises, comply with
24		the operating and efficiency standards applicable to
25		"qualifying facilities" specified in title 18 Code of
26		Federal Regulations Section 292.205 as in effect on the

SB0025 Enrolled - 768 - LRB104 07069 BAB 17106 b
1		effective date of this amendatory Act of 1999;
2		(iii) the retail customer on whose premises the
3		facilities are located either has an exclusive right to
4		receive, and corresponding obligation to pay for, all of
5		the electrical capacity of the facility, or in the case of
6		a cogeneration facility that has been designed to meet the
7		retail customer's thermal energy requirements at that
8		premises, an identified amount of the electrical capacity
9		of the facility, over a minimum 5-year period; and
10		(iv) if the cogeneration facility is sized for the
11		retail customer's thermal load at that premises but
12		exceeds the electrical load, any sales of excess power or
13		energy are made only at wholesale, are subject to the
14		jurisdiction of the Federal Energy Regulatory Commission,
15		and are not for the purpose of circumventing the
16		provisions of this subsection (f).
17		If a generation facility located at a retail customer's
18		premises does not meet the above criteria, an electric utility
19		implementing transition charges shall implement a transition
20		charge until December 31, 2006 for any power and energy taken
21		by such retail customer from such facility as if such power and
22		energy had been delivered by the electric utility. Provided,
23		however, that an industrial retail customer that is taking
24		power from a generation facility that does not meet the above
25		criteria but that is located on such customer's premises will
26		not be subject to a transition charge for the power and energy

SB0025 Enrolled - 769 - LRB104 07069 BAB 17106 b
1		taken by such retail customer from such generation facility if
2		the facility does not serve any other retail customer and
3		either was installed on behalf of the customer and for its own
4		use prior to January 1, 1997, or is both predominantly fueled
5		by byproducts of such customer's manufacturing process at such
6		premises and sells or offers an average of 300 megawatts or
7		more of electricity produced from such generation facility
8		into the wholesale market. Such charges shall be calculated as
9		provided in Section 16-102, and shall be collected on each
10		kilowatt-hour delivered under a delivery services tariff to a
11		retail customer from the date the customer first takes
12		delivery services until December 31, 2006 except as provided
13		in subsection (h) of this Section. Provided, however, that an
14		electric utility, other than an electric utility providing
15		service to at least 1,000,000 customers in this State on
16		January 1, 1999, shall be entitled to petition for entry of an
17		order by the Commission authorizing the electric utility to
18		implement transition charges for an additional period ending
19		no later than December 31, 2008. The electric utility shall
20		file its petition with supporting evidence no earlier than 16
21		months, and no later than 12 months, prior to December 31,
22		2006. The Commission shall hold a hearing on the electric
23		utility's petition and shall enter its order no later than 8
24		months after the petition is filed. The Commission shall
25		determine whether and to what extent the electric utility
26		shall be authorized to implement transition charges for an

SB0025 Enrolled - 770 - LRB104 07069 BAB 17106 b
1		additional period. The Commission may authorize the electric
2		utility to implement transition charges for some or all of the
3		additional period, and shall determine the mitigation factors
4		to be used in implementing such transition charges; provided,
5		that the Commission shall not authorize mitigation factors
6		less than 110% of those in effect during the 12 months ended
7		December 31, 2006. In making its determination, the Commission
8		shall consider the following factors: the necessity to
9		implement transition charges for an additional period in order
10		to maintain the financial integrity of the electric utility;
11		the prudence of the electric utility's actions in reducing its
12		costs since the effective date of this amendatory Act of 1997;
13		the ability of the electric utility to provide safe, adequate
14		and reliable service to retail customers in its service area;
15		and the impact on competition of allowing the electric utility
16		to implement transition charges for the additional period.
17		(g) The electric utility shall file tariffs that establish
18		the transition charges to be paid by each class of customers to
19		the electric utility in conjunction with the provision of
20		delivery services. The electric utility's tariffs shall define
21		the classes of its customers for purposes of calculating
22		transition charges. The electric utility's tariffs shall
23		provide for the calculation of transition charges on a
24		customer-specific basis for any retail customer whose average
25		monthly maximum electrical demand on the electric utility's
26		system during the 6 months with the customer's highest monthly

SB0025 Enrolled - 771 - LRB104 07069 BAB 17106 b
1		maximum electrical demands equals or exceeds 3.0 megawatts for
2		electric utilities having more than 1,000,000 customers, and
3		for other electric utilities for any customer that has an
4		average monthly maximum electrical demand on the electric
5		utility's system of one megawatt or more, and (A) for which
6		there exists data on the customer's usage during the 3 years
7		preceding the date that the customer became eligible to take
8		delivery services, or (B) for which there does not exist data
9		on the customer's usage during the 3 years preceding the date
10		that the customer became eligible to take delivery services,
11		if in the electric utility's reasonable judgment there exists
12		comparable usage information or a sufficient basis to develop
13		such information, and further provided that the electric
14		utility can require customers for which an individual
15		calculation is made to sign contracts that set forth the
16		transition charges to be paid by the customer to the electric
17		utility pursuant to the tariff.
18		(h) An electric utility shall also be entitled to file
19		tariffs that allow it to collect transition charges from
20		retail customers in the electric utility's service area that
21		do not take delivery services but that take electric power or
22		energy from an alternative retail electric supplier or from an
23		electric utility other than the electric utility in whose
24		service area the customer is located. Such charges shall be
25		calculated, in accordance with the definition of transition
26		charges in Section 16-102, for the period of time that the

SB0025 Enrolled - 772 - LRB104 07069 BAB 17106 b
1		customer would be obligated to pay transition charges if it
2		were taking delivery services, except that no deduction for
3		delivery services revenues shall be made in such calculation,
4		and usage data from the customer's class shall be used where
5		historical usage data is not available for the individual
6		customer. The customer shall be obligated to pay such charges
7		on a lump sum basis on or before the date on which the customer
8		commences to take service from the alternative retail electric
9		supplier or other electric utility, provided, that the
10		electric utility in whose service area the customer is located
11		shall offer the customer the option of signing a contract
12		pursuant to which the customer pays such charges ratably over
13		the period in which the charges would otherwise have applied.
14		(i) An electric utility shall be entitled to add to the
15		bills of delivery services customers charges pursuant to
16		Sections 9-221, 9-222 (except as provided in Section 9-222.1),
17		and Section 16-114 of this Act, Section 5-5 of the Electricity
18		Infrastructure Maintenance Fee Law, Section 6-5 of the
19		Renewable Energy, Energy Efficiency, and Coal Resources
20		Development Law of 1997, and Section 13 of the Energy
21		Assistance Act.
22		(i-5) An electric utility required to impose the Coal to
23		Solar and Energy Storage Initiative Charge provided for in
24		subsection (c-5) of Section 1-75 of the Illinois Power Agency
25		Act shall add such charge to the bills of its delivery services
26		customers pursuant to the terms of a tariff conforming to the

SB0025 Enrolled - 773 - LRB104 07069 BAB 17106 b
1		requirements of subsection (c-5) of Section 1-75 of the
2		Illinois Power Agency Act and this subsection (i-5) and filed
3		with and approved by the Commission. The electric utility
4		shall file its proposed tariff with the Commission on or
5		before July 1, 2022 to be effective, after review and approval
6		or modification by the Commission, beginning January 1, 2023.
7		On or before December 1, 2022, the Commission shall review the
8		electric utility's proposed tariff, including by conducting a
9		docketed proceeding if deemed necessary by the Commission, and
10		shall approve the proposed tariff or direct the electric
11		utility to make modifications the Commission finds necessary
12		for the tariff to conform to the requirements of subsection
13		(c-5) of Section 1-75 of the Illinois Power Agency Act and this
14		subsection (i-5). The electric utility's tariff shall provide
15		for imposition of the Coal to Solar and Energy Storage
16		Initiative Charge on a per-kilowatthour basis to all
17		kilowatthours delivered by the electric utility to its
18		delivery services customers. The tariff shall provide for the
19		calculation of the Coal to Solar and Energy Storage Initiative
20		Charge to be in effect for the year beginning January 1, 2023
21		and each year beginning January 1 thereafter, sufficient to
22		collect the electric utility's estimated payment obligations
23		for the delivery year beginning the following June 1 under
24		contracts for purchase of renewable energy credits entered
25		into pursuant to subsection (c-5) of Section 1-75 of the
26		Illinois Power Agency Act and the obligations of the

SB0025 Enrolled - 774 - LRB104 07069 BAB 17106 b
1		Department of Commerce and Economic Opportunity, or any
2		successor department or agency, which for purposes of this
3		subsection (i-5) shall be referred to as the Department, to
4		make grant payments during such delivery year from the Coal to
5		Solar and Energy Storage Initiative Fund pursuant to grant
6		contracts entered into pursuant to subsection (c-5) of Section
7		1-75 of the Illinois Power Agency Act, and using the electric
8		utility's kilowatthour deliveries to its delivery services
9		customers during the delivery year ended May 31 of the
10		preceding calendar year. On or before November 1 of each year
11		beginning November 1, 2022, the Department shall notify the
12		electric utilities of the amount of the Department's estimated
13		obligations for grant payments during the delivery year
14		beginning the following June 1 pursuant to grant contracts
15		entered into pursuant to subsection (c-5) of Section 1-75 of
16		the Illinois Power Agency Act; and each electric utility shall
17		incorporate in the calculation of its Coal to Solar and Energy
18		Storage Initiative Charge the fractional portion of the
19		Department's estimated obligations equal to the electric
20		utility's kilowatthour deliveries to its delivery services
21		customers in the delivery year ended the preceding May 31
22		divided by the aggregate deliveries of both electric utilities
23		to delivery services customers in such delivery year. The
24		electric utility shall remit on a monthly basis to the State
25		Treasurer, for deposit in the Coal to Solar and Energy Storage
26		Initiative Fund provided for in subsection (c-5) of Section

SB0025 Enrolled - 775 - LRB104 07069 BAB 17106 b
1		1-75 of the Illinois Power Agency Act, the electric utility's
2		collections of the Coal to Solar and Energy Storage Initiative
3		Charge estimated to be needed by the Department for grant
4		payments pursuant to grant contracts entered into pursuant to
5		subsection (c-5) of Section 1-75 of the Illinois Power Agency
6		Act. The initial charge under the electric utility's tariff
7		shall be effective for kilowatthours delivered beginning
8		January 1, 2023, and thereafter shall be revised to be
9		effective January 1, 2024 and each January 1 thereafter, based
10		on the payment obligations for the delivery year beginning the
11		following June 1. The tariff shall provide for the electric
12		utility to make an annual filing with the Commission on or
13		before November 15 of each year, beginning in 2023, setting
14		forth the Coal to Solar and Energy Storage Initiative Charge
15		to be in effect for the year beginning the following January 1.
16		The electric utility's tariff shall also provide that the
17		electric utility shall make a filing with the Commission on or
18		before August 1 of each year beginning in 2024 setting forth a
19		reconciliation, for the delivery year ended the preceding May
20		31, of the electric utility's collections of the Coal to Solar
21		and Energy Storage Initiative Charge against actual payments
22		for renewable energy credits pursuant to contracts entered
23		into, and the actual grant payments by the Department pursuant
24		to grant contracts entered into, pursuant to subsection (c-5)
25		of Section 1-75 of the Illinois Power Agency Act. The tariff
26		shall provide that any excess or shortfall of collections to

SB0025 Enrolled - 776 - LRB104 07069 BAB 17106 b
1		payments shall be deducted from or added to, on a
2		per-kilowatthour basis, the Coal to Solar and Energy Storage
3		Initiative Charge, over the 6-month period beginning October 1
4		of that calendar year.
5		(j) If a retail customer that obtains electric power and
6		energy from cogeneration or self-generation facilities
7		installed for its own use on or before January 1, 1997,
8		subsequently takes service from an alternative retail electric
9		supplier or an electric utility other than the electric
10		utility in whose service area the customer is located for any
11		portion of the customer's electric power and energy
12		requirements formerly obtained from those facilities
13		(including that amount purchased from the utility in lieu of
14		such generation and not as standby power purchases, under a
15		cogeneration displacement tariff in effect as of the effective
16		date of this amendatory Act of 1997), the transition charges
17		otherwise applicable pursuant to subsections (f), (g), or (h)
18		of this Section shall not be applicable in any year to that
19		portion of the customer's electric power and energy
20		requirements formerly obtained from those facilities,
21		provided, that for purposes of this subsection (j), such
22		portion shall not exceed the average number of kilowatt-hours
23		per year obtained from the cogeneration or self-generation
24		facilities during the 3 years prior to the date on which the
25		customer became eligible for delivery services, except as
26		provided in subsection (f) of Section 16-110.

SB0025 Enrolled - 777 - LRB104 07069 BAB 17106 b
1		(k) The electric utility shall be entitled to recover
2		through tariffed charges all of the costs associated with the
3		purchase of zero emission credits from zero emission
4		facilities to meet the requirements of subsection (d-5) of
5		Section 1-75 of the Illinois Power Agency Act and all of the
6		costs associated with the purchase of carbon mitigation
7		credits from carbon-free energy resources to meet the
8		requirements of subsection (d-10) of Section 1-75 of the
9		Illinois Power Agency Act. Such costs shall include the costs
10		of procuring the zero emission credits and carbon mitigation
11		credits from carbon-free energy resources, as well as the
12		reasonable costs that the utility incurs as part of the
13		procurement processes and to implement and comply with plans
14		and processes approved by the Commission under subsections
15		(d-5) and (d-10). The costs shall be allocated across all
16		retail customers through a single, uniform cents per
17		kilowatt-hour charge applicable to all retail customers, which
18		shall appear as a separate line item on each customer's bill.
19		The electric utility shall be entitled to recover through
20		tariffed charges approved by the Commission all of the prudent
21		and reasonable costs associated with energy storage resources
22		procurements to meet the energy storage system portfolio
23		standard of subsection (d-20) of Section 1-75 of the Illinois
24		Power Agency Act. Such costs shall include the contract costs
25		for the energy storage system resources and the prudent and
26		reasonable costs that the utility incurs as part of the

SB0025 Enrolled - 778 - LRB104 07069 BAB 17106 b
1		procurement processes and in implementing and complying with
2		plans and processes approved by the Commission under
3		subsection (d-20). The costs associated with the purchase of
4		energy storage system resources shall be allocated across all
5		retail customers in proportion to the amount of energy storage
6		system resources the utility procures for such customers
7		through a single, uniform cents per kilowatt-hour charge
8		applicable to such retail customers, which shall appear as a
9		separate line item on each customer's bill. Beginning June 1,
10		2017, the electric utility shall be entitled to recover
11		through tariffed charges all of the costs associated with the
12		purchase of renewable energy resources to meet the renewable
13		energy resource standards of subsection (c) of Section 1-75 of
14		the Illinois Power Agency Act, under procurement plans as
15		approved in accordance with that Section and Section 16-111.5
16		of this Act. Such costs shall include the costs of procuring
17		the renewable energy resources, as well as the reasonable
18		costs that the utility incurs as part of the procurement
19		processes and to implement and comply with plans and processes
20		approved by the Commission under such Sections. The costs
21		associated with the purchase of renewable energy resources
22		shall be allocated across all retail customers in proportion
23		to the amount of renewable energy resources the utility
24		procures for such customers through a single, uniform cents
25		per kilowatt-hour charge applicable to such retail customers,
26		which shall appear as a separate line item on each such

SB0025 Enrolled - 779 - LRB104 07069 BAB 17106 b
1		customer's bill. The credits, costs, and penalties associated
2		with the self-direct renewable portfolio standard compliance
3		program described in subparagraph (R) of paragraph (1) of
4		subsection (c) of Section 1-75 of the Illinois Power Agency
5		Act shall be allocated to approved eligible self-direct
6		customers by the utility in a cents per kilowatt-hour credit,
7		cost, or penalty, which shall appear as a separate line item on
8		each such customer's bill.
9		Notwithstanding whether the Commission has approved the
10		initial long-term renewable resources procurement plan as of
11		June 1, 2017, an electric utility shall place new tariffed
12		charges into effect beginning with the June 2017 monthly
13		billing period, to the extent practicable, to begin recovering
14		the costs of procuring renewable energy resources, as those
15		charges are calculated under the limitations described in
16		subparagraph (E) of paragraph (1) of subsection (c) of Section
17		1-75 of the Illinois Power Agency Act. Notwithstanding the
18		date on which the utility places such new tariffed charges
19		into effect, the utility shall be permitted to collect the
20		charges under such tariff as if the tariff had been in effect
21		beginning with the first day of the June 2017 monthly billing
22		period. For the delivery years commencing June 1, 2017, June
23		1, 2018, June 1, 2019, and each delivery year thereafter, the
24		electric utility shall deposit into a separate interest
25		bearing account of a financial institution the monies
26		collected under the tariffed charges. Money collected from

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

SB0025 Enrolled - 781 - LRB104 07069 BAB 17106 b
1		tariffed charges consistent with this subsection (k). The
2		determination as to whether any excess funds were collected
3		during a given delivery year for the purchase of renewable
4		energy resources, and the crediting of any excess funds back
5		to retail customers, shall not be made until after the close of
6		the delivery year, which will ensure that the maximum amount
7		of funds is available to implement the approved long-term
8		renewable resources procurement plan during a given delivery
9		year. The amount of excess funds eligible to be credited back
10		to retail customers shall be reduced by an amount equal to the
11		payment obligations required by any contracts entered into by
12		an electric utility under contracts described in subsection
13		(b) of Section 1-56 and subsection (c) of Section 1-75 of the
14		Illinois Power Agency Act, even if such payments have not yet
15		been made and regardless of the delivery year in which those
16		payment obligations were incurred. Notwithstanding anything to
17		the contrary, including in tariffs authorized by this
18		subsection (k) in effect before the effective date of this
19		amendatory Act of the 102nd General Assembly, all unspent
20		funds as of May 31, 2021, excluding any funds credited to
21		customers during any utility billing cycle that commences
22		prior to the effective date of this amendatory Act of the 102nd
23		General Assembly, shall remain in the utility account and
24		shall on a first in, first out basis be used toward utility
25		payment obligations under contracts described in subsection
26		(b) of Section 1-56 and subsection (c) of Section 1-75 of the

SB0025 Enrolled - 782 - LRB104 07069 BAB 17106 b
1		Illinois Power Agency Act. The electric utility's collections
2		under such automatic adjustment clause tariffs to recover the
3		costs of renewable energy resources, zero emission credits
4		from zero emission facilities, energy storage resources, and
5		carbon mitigation credits from carbon-free energy resources
6		shall be subject to separate annual review, reconciliation,
7		and true-up against actual costs by the Commission under a
8		procedure that shall be specified in the electric utility's
9		automatic adjustment clause tariffs and that shall be approved
10		by the Commission in connection with its approval of such
11		tariffs. The procedure shall provide that any difference
12		between the electric utility's collections for energy storage
13		resources, zero emission credits, and carbon mitigation
14		credits under the automatic adjustment charges for an annual
15		period and the electric utility's actual costs of energy
16		storage resources, zero emission credits from zero emission
17		facilities, and carbon mitigation credits from carbon-free
18		energy resources for that same annual period shall be refunded
19		to or collected from, as applicable, the electric utility's
20		retail customers in subsequent periods.
21		Nothing in this subsection (k) is intended to affect,
22		limit, or change the right of the electric utility to recover
23		the costs associated with the procurement of renewable energy
24		resources for periods commencing before, on, or after June 1,
25		2017, as otherwise provided in the Illinois Power Agency Act.
26		The funding available under this subsection (k), if any,

SB0025 Enrolled - 783 - LRB104 07069 BAB 17106 b
1		for the programs described under subsection (b) of Section
2		1-56 of the Illinois Power Agency Act shall not reduce the
3		amount of funding for the programs described in subparagraph
4		(O) of paragraph (1) of subsection (c) of Section 1-75 of the
5		Illinois Power Agency Act. If funding is available under this
6		subsection (k) for programs described under subsection (b) of
7		Section 1-56 of the Illinois Power Agency Act, then the
8		long-term renewable resources plan shall provide for the
9		Agency to procure contracts in an amount that does not exceed
10		the funding, and the contracts approved by the Commission
11		shall be executed by the applicable utility or utilities.
12		(l) A utility that has terminated any contract executed
13		under subsection (d-5) or (d-10) of Section 1-75 of the
14		Illinois Power Agency Act shall be entitled to recover any
15		remaining balance associated with the purchase of zero
16		emission credits prior to such termination, and such utility
17		shall also apply a credit to its retail customer bills in the
18		event of any over-collection.
19		(m)(1) An electric utility that recovers its costs of
20		procuring zero emission credits from zero emission facilities
21		through a cents-per-kilowatthour charge under subsection (k)
22		of this Section shall be subject to the requirements of this
23		subsection (m). Notwithstanding anything to the contrary, such
24		electric utility shall, beginning on April 30, 2018, and each
25		April 30 thereafter until April 30, 2026, calculate whether
26		any reduction must be applied to such cents-per-kilowatthour

SB0025 Enrolled - 784 - LRB104 07069 BAB 17106 b
1		charge that is paid by retail customers of the electric
2		utility that have opted out of subsections (a) through (j) of
3		Section 8-103B of this Act under subsection (l) of Section
4		8-103B. Such charge shall be reduced for such customers for
5		the next delivery year commencing on June 1 based on the amount
6		necessary, if any, to limit the annual estimated average net
7		increase for the prior calendar year due to the future energy
8		investment costs to no more than 1.3% of 5.98 cents per
9		kilowatt-hour, which is the average amount paid per
10		kilowatthour for electric service during the year ending
11		December 31, 2015 by Illinois industrial retail customers, as
12		reported to the Edison Electric Institute.
13		The calculations required by this subsection (m) shall be
14		made only once for each year, and no subsequent rate impact
15		determinations shall be made.
16		(2) For purposes of this Section, "future energy
17		investment costs" shall be calculated by subtracting the
18		cents-per-kilowatthour charge identified in subparagraph (A)
19		of this paragraph (2) from the sum of the
20		cents-per-kilowatthour charges identified in subparagraph (B)
21		of this paragraph (2):
22		(A) The cents-per-kilowatthour charge identified in
23		the electric utility's tariff placed into effect under
24		Section 8-103 of the Public Utilities Act that, on
25		December 1, 2016, was applicable to those retail customers
26		that have opted out of subsections (a) through (j) of

SB0025 Enrolled - 785 - LRB104 07069 BAB 17106 b
1		Section 8-103B of this Act under subsection (l) of Section
2		8-103B.
3		(B) The sum of the following cents-per-kilowatthour
4		charges applicable to those retail customers that have
5		opted out of subsections (a) through (j) of Section 8-103B
6		of this Act under subsection (l) of Section 8-103B,
7		provided that if one or more of the following charges has
8		been in effect and applied to such customers for more than
9		one calendar year, then each charge shall be equal to the
10		average of the charges applied over a period that
11		commences with the calendar year ending December 31, 2017
12		and ends with the most recently completed calendar year
13		prior to the calculation required by this subsection (m):
14		(i) the cents-per-kilowatthour charge to recover
15		the costs incurred by the utility under subsection
16		(d-5) of Section 1-75 of the Illinois Power Agency
17		Act, adjusted for any reductions required under this
18		subsection (m); and
19		(ii) the cents-per-kilowatthour charge to recover
20		the costs incurred by the utility under Section
21		16-107.6 of the Public Utilities Act.
22		If no charge was applied for a given calendar year
23		under item (i) or (ii) of this subparagraph (B), then the
24		value of the charge for that year shall be zero.
25		(3) If a reduction is required by the calculation
26		performed under this subsection (m), then the amount of the

SB0025 Enrolled - 786 - LRB104 07069 BAB 17106 b
1		reduction shall be multiplied by the number of years reflected
2		in the averages calculated under subparagraph (B) of paragraph
3		(2) of this subsection (m). Such reduction shall be applied to
4		the cents-per-kilowatthour charge that is applicable to those
5		retail customers that have opted out of subsections (a)
6		through (j) of Section 8-103B of this Act under subsection (l)
7		of Section 8-103B beginning with the next delivery year
8		commencing after the date of the calculation required by this
9		subsection (m).
10		(4) The electric utility shall file a notice with the
11		Commission on May 1 of 2018 and each May 1 thereafter until May
12		1, 2026 containing the reduction, if any, which must be
13		applied for the delivery year which begins in the year of the
14		filing. The notice shall contain the calculations made
15		pursuant to this Section. By October 1 of each year beginning
16		in 2018, each electric utility shall notify the Commission if
17		it appears, based on an estimate of the calculation required
18		in this subsection (m), that a reduction will be required in
19		the next year.
20		(Source: P.A. 102-662, eff. 9-15-21.)
21		(220 ILCS 5/16-108.19)
22		Sec. 16-108.19. Division of Integrated Distribution
23		Planning.
24		(a) The Commission shall employ establish the Division of
25		Integrated Distribution Planning within the Bureau of Public

SB0025 Enrolled - 787 - LRB104 07069 BAB 17106 b
1		Utilities. The Division shall be staffed by no less than 13
2		professionals, including engineers, rate analysts,
3		accountants, policy analysts, utility research and analysis
4		analysts, cybersecurity analysts, informational technology
5		specialists, and lawyers, and other personnel deemed necessary
6		and appropriate by the Executive Director to review and
7		evaluate Integrated Grid Plans, updates to Integrated Grid
8		Plans, audits, and other duties as assigned. The personnel may
9		be organized or assigned into departments, bureaus, sections,
10		or divisions as determined by the Executive Director pursuant
11		to the authority granted under this Section by the Chief of the
12		Public Utilities Bureau.
13		(b) The Division of Integrated Distribution Planning shall
14		be established by January 1, 2022.
15		(Source: P.A. 102-662, eff. 9-15-21.)
16		(220 ILCS 5/16-108.30)
17		Sec. 16-108.30. Energy Transition Assistance Fund.
18		(a) The Energy Transition Assistance Fund is hereby
19		created as a special fund in the State treasury Treasury. The
20		Energy Transition Assistance Fund is authorized to receive
21		moneys collected pursuant to this Section. Subject to
22		appropriation, the Department of Commerce and Economic
23		Opportunity shall use moneys from the Energy Transition
24		Assistance Fund consistent with the purposes of this Act.
25		(b) An electric utility serving more than 500,000

SB0025 Enrolled - 788 - LRB104 07069 BAB 17106 b
1		customers in the State shall assess an energy transition
2		assistance charge on all its retail customers for the Energy
3		Transition Assistance Fund. The utility's total charge shall
4		be set based upon the value determined by the Department of
5		Commerce and Economic Opportunity pursuant to subsection (d)
6		or (e), as applicable, of Section 605-1075 of the Department
7		of Commerce and Economic Opportunity Law of the Civil
8		Administrative Code of Illinois. For each utility, the charge
9		shall be recovered through a single, uniform cents per
10		kilowatt-hour charge applicable to all retail customers. For
11		each utility, the charge shall not exceed 1.45% 1.3% of the
12		amount paid per kilowatthour by eligible retail customers
13		during the year ending May 31, 2009. Beginning January 1,
14		2028, the limitation shall be increased by an additional 0.636
15		percentage points of the amount paid per kilowatt-hour by
16		eligible retail customers during the year ending May 31, 2009,
17		which would collect the equivalent of the average annual
18		budget of the programs administered by the utilities under
19		Section 45 of the Electric Vehicle Act for the years 2026
20		through 2028.
21		(c) Within 75 days of the effective date of this
22		amendatory Act of the 102nd General Assembly, each electric
23		utility serving more than 500,000 customers in the State shall
24		file with the Illinois Commerce Commission tariffs
25		incorporating the energy transition assistance charge in other
26		charges stated in such tariffs, which energy transition

SB0025 Enrolled - 789 - LRB104 07069 BAB 17106 b
1		assistance charges shall become effective no later than the
2		beginning of the first billing cycle that begins on or after
3		January 1, 2022. Each electric utility serving more than
4		500,000 customers in the State shall, prior to the beginning
5		of each calendar year starting with calendar year 2023, file
6		with the Illinois Commerce Commission tariff revisions to
7		incorporate annual revisions to the energy transition
8		assistance charge as prescribed by the Department of Commerce
9		and Economic Opportunity pursuant to Section 605-1075 of the
10		Department of Commerce and Economic Opportunity Law of the
11		Civil Administrative Code of Illinois so that such revision
12		becomes effective no later than the beginning of the first
13		billing cycle in each respective year.
14		(d) The energy transition assistance charge shall be
15		considered a charge for public utility service.
16		(e) By the 20th day of the month following the month in
17		which the charges imposed by this Section were collected, each
18		electric utility serving more than 500,000 customers in the
19		State shall remit to Department of Revenue all moneys received
20		as payment of the energy transition assistance charge on a
21		return prescribed and furnished by the Department of Revenue
22		showing such information as the Department of Revenue may
23		reasonably require. If a customer makes a partial payment, a
24		public utility may apply such partial payments first to
25		amounts owed to the utility. No customer may be subjected to
26		disconnection of his or her utility service for failure to pay

SB0025 Enrolled - 790 - LRB104 07069 BAB 17106 b
1		the energy transition assistance charge.
2		If any payment provided for in this subsection exceeds the
3		electric utility's liabilities under this Act, as shown on an
4		original return, the Department may authorize the electric
5		utility to credit such excess payment against liability
6		subsequently to be remitted to the Department under this Act,
7		in accordance with reasonable rules adopted by the Department.
8		All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e,
9		5f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13
10		of the Retailers' Occupation Tax Act that are not inconsistent
11		with this Act apply, as far as practicable, to the charge
12		imposed by this Act to the same extent as if those provisions
13		were included in this Act. References in the incorporated
14		Sections of the Retailers' Occupation Tax Act to retailers, to
15		sellers, or to persons engaged in the business of selling
16		tangible personal property mean persons required to remit the
17		charge imposed under this Act.
18		(f) The Department of Revenue shall deposit into the
19		Energy Transition Assistance Fund all moneys remitted to it in
20		accordance with this Section.
21		(g) The Department of Revenue may establish such rules as
22		it deems necessary to implement this Section.
23		(h) The Department of Commerce and Economic Opportunity
24		may establish such rules as it deems necessary to implement
25		this Section.
26		(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)

SB0025 Enrolled - 791 - LRB104 07069 BAB 17106 b
1		(220 ILCS 5/16-111.5)
2		Sec. 16-111.5. Provisions relating to procurement.
3		(a) An electric utility that on December 31, 2005 served
4		at least 100,000 customers in Illinois shall procure power and
5		energy for its eligible retail customers in accordance with
6		the applicable provisions set forth in Section 1-75 of the
7		Illinois Power Agency Act and this Section. Beginning with the
8		delivery year commencing on June 1, 2017, such electric
9		utility shall also procure zero emission credits from zero
10		emission facilities in accordance with the applicable
11		provisions set forth in Section 1-75 of the Illinois Power
12		Agency Act, and, for years beginning on or after June 1, 2017,
13		the utility shall procure renewable energy resources in
14		accordance with the applicable provisions set forth in Section
15		1-75 of the Illinois Power Agency Act and this Section.
16		Beginning with the delivery year commencing on June 1, 2022,
17		an electric utility serving over 3,000,000 customers shall
18		also procure carbon mitigation credits from carbon-free energy
19		resources in accordance with the applicable provisions set
20		forth in Section 1-75 of the Illinois Power Agency Act and this
21		Section. Beginning with the delivery year commencing on June
22		1, 2026, an electric utility serving more than 300,000
23		customers in the State as of January 1, 2019 shall also procure
24		energy storage resources in accordance with the applicable
25		provisions of subsection (d-20) of Section 1-75 of the

SB0025 Enrolled - 792 - LRB104 07069 BAB 17106 b
1		Illinois Power Agency Act and this Section. A small
2		multi-jurisdictional electric utility that on December 31,
3		2005 served less than 100,000 customers in Illinois may elect
4		to procure power and energy for all or a portion of its
5		eligible Illinois retail customers in accordance with the
6		applicable provisions set forth in this Section and Section
7		1-75 of the Illinois Power Agency Act. This Section shall not
8		apply to a small multi-jurisdictional utility until such time
9		as a small multi-jurisdictional utility requests the Illinois
10		Power Agency to prepare a procurement plan for its eligible
11		retail customers. "Eligible retail customers" for the purposes
12		of this Section means those retail customers that purchase
13		power and energy from the electric utility under fixed-price
14		bundled service tariffs, other than those retail customers
15		whose service is declared or deemed competitive under Section
16		16-113 and those other customer groups specified in this
17		Section, including self-generating customers, customers
18		electing hourly pricing, or those customers who are otherwise
19		ineligible for fixed-price bundled tariff service. Except as
20		otherwise provided for in subsection (b-10), for For those
21		customers that are excluded from the procurement plan's
22		electric supply service requirements, and the utility shall
23		procure any supply requirements, including capacity, ancillary
24		services, and hourly priced energy, in the applicable markets
25		as needed to serve those customers, provided that the utility
26		may include in its procurement plan load requirements for the

SB0025 Enrolled - 793 - LRB104 07069 BAB 17106 b
1		load that is associated with those retail customers whose
2		service has been declared or deemed competitive pursuant to
3		Section 16-113 of this Act to the extent that those customers
4		are purchasing power and energy during one of the transition
5		periods identified in subsection (b) of Section 16-113 of this
6		Act.
7		(b) A procurement plan shall be prepared for each electric
8		utility consistent with the applicable requirements of the
9		Illinois Power Agency Act and this Section. For purposes of
10		this Section, Illinois electric utilities that are affiliated
11		by virtue of a common parent company are considered to be a
12		single electric utility. Small multi-jurisdictional utilities
13		may request a procurement plan for a portion of or all of its
14		Illinois load. Each procurement plan shall analyze the
15		projected balance of supply and demand for those retail
16		customers to be included in the plan's electric supply service
17		requirements over a 5-year period, with the first planning
18		year beginning on June 1 of the year following the year in
19		which the plan is filed. The plan shall specifically identify
20		the wholesale products to be procured following plan approval,
21		and shall follow all the requirements set forth in the Public
22		Utilities Act and all applicable State and federal laws,
23		statutes, rules, or regulations, as well as Commission orders.
24		Nothing in this Section precludes consideration of contracts
25		longer than 5 years and related forecast data. Unless
26		specified otherwise in this Section, in the procurement plan

SB0025 Enrolled - 794 - LRB104 07069 BAB 17106 b
1		or in the implementing tariff, any procurement occurring in
2		accordance with this plan shall be competitively bid through a
3		request for proposals process. Approval and implementation of
4		the procurement plan shall be subject to review and approval
5		by the Commission according to the provisions set forth in
6		this Section. A procurement plan shall include each of the
7		following components:
8		(1) Hourly load analysis. This analysis shall include:
9		(i) multi-year historical analysis of hourly
10		loads;
11		(ii) switching trends and competitive retail
12		market analysis;
13		(iii) known or projected changes to future loads;
14		and
15		(iv) growth forecasts by customer class.
16		(2) Analysis of the impact of any demand side and
17		renewable energy initiatives. This analysis shall include:
18		(i) the impact of demand response programs and
19		energy efficiency programs, both current and
20		projected; for small multi-jurisdictional utilities,
21		the impact of demand response and energy efficiency
22		programs approved pursuant to Section 8-408 of this
23		Act, both current and projected; and
24		(ii) supply side needs that are projected to be
25		offset by purchases of renewable energy resources, if
26		any.

SB0025 Enrolled - 795 - LRB104 07069 BAB 17106 b
1		(3) A plan for meeting the expected load requirements
2		that will not be met through preexisting contracts. This
3		plan shall include:
4		(i) definitions of the different Illinois retail
5		customer classes for which supply is being purchased;
6		(ii) the proposed mix of demand-response products
7		for which contracts will be executed during the next
8		year. For small multi-jurisdictional electric
9		utilities that on December 31, 2005 served fewer than
10		100,000 customers in Illinois, these shall be defined
11		as demand-response products offered in an energy
12		efficiency plan approved pursuant to Section 8-408 of
13		this Act. The cost-effective demand-response measures
14		shall be procured whenever the cost is lower than
15		procuring comparable capacity products, provided that
16		such products shall:
17		(A) be procured by a demand-response provider
18		from those retail customers included in the plan's
19		electric supply service requirements;
20		(B) at least satisfy the demand-response
21		requirements of the regional transmission
22		organization market in which the utility's service
23		territory is located, including, but not limited
24		to, any applicable capacity or dispatch
25		requirements;
26		(C) provide for customers' participation in

SB0025 Enrolled - 796 - LRB104 07069 BAB 17106 b
1		the stream of benefits produced by the
2		demand-response products;
3		(D) provide for reimbursement by the
4		demand-response provider of the utility for any
5		costs incurred as a result of the failure of the
6		supplier of such products to perform its
7		obligations thereunder; and
8		(E) meet the same credit requirements as apply
9		to suppliers of capacity, in the applicable
10		regional transmission organization market;
11		(iii) monthly forecasted system supply
12		requirements, including expected minimum, maximum, and
13		average values for the planning period;
14		(iv) the proposed mix and selection of standard
15		wholesale products for which contracts will be
16		executed during the next year, separately or in
17		combination, to meet that portion of its load
18		requirements not met through pre-existing contracts,
19		including but not limited to monthly 5 x 16 peak period
20		block energy, monthly off-peak wrap energy, monthly 7
21		x 24 energy, annual 5 x 16 energy, other standardized
22		energy or capacity products designed to provide
23		eligible retail customer benefits from commercially
24		deployed advanced technologies including but not
25		limited to high voltage direct current converter
26		stations, as such term is defined in Section 1-10 of

SB0025 Enrolled - 797 - LRB104 07069 BAB 17106 b
1		the Illinois Power Agency Act, whether or not such
2		product is currently available in wholesale markets,
3		annual off-peak wrap energy, annual 7 x 24 energy,
4		monthly capacity, annual capacity, peak load capacity
5		obligations, capacity purchase plan, and ancillary
6		services;
7		(v) proposed term structures for each wholesale
8		product type included in the proposed procurement plan
9		portfolio of products; and
10		(vi) an assessment of the price risk, load
11		uncertainty, and other factors that are associated
12		with the proposed procurement plan; this assessment,
13		to the extent possible, shall include an analysis of
14		the following factors: contract terms, time frames for
15		securing products or services, fuel costs, weather
16		patterns, transmission costs, market conditions, and
17		the governmental regulatory environment; the proposed
18		procurement plan shall also identify alternatives for
19		those portfolio measures that are identified as having
20		significant price risk and mitigation in the form of
21		additional retail customer and ratepayer price,
22		reliability, and environmental benefits from
23		standardized energy products delivered from
24		commercially deployed advanced technologies,
25		including, but not limited to, high voltage direct
26		current converter stations, as such term is defined in

SB0025 Enrolled - 798 - LRB104 07069 BAB 17106 b
1		Section 1-10 of the Illinois Power Agency Act, whether
2		or not such product is currently available in
3		wholesale markets.
4		(4) Proposed procedures for balancing loads. The
5		procurement plan shall include, for load requirements
6		included in the procurement plan, the process for (i)
7		hourly balancing of supply and demand and (ii) the
8		criteria for portfolio re-balancing in the event of
9		significant shifts in load.
10		(5) Long-Term Renewable Resources Procurement Plan.
11		The Agency shall prepare a long-term renewable resources
12		procurement plan for the procurement of renewable energy
13		credits under Sections 1-56 and 1-75 of the Illinois Power
14		Agency Act for delivery beginning in the 2017 delivery
15		year.
16		(i) The initial long-term renewable resources
17		procurement plan and all subsequent revisions shall be
18		subject to review and approval by the Commission. For
19		the purposes of this Section, "delivery year" has the
20		same meaning as in Section 1-10 of the Illinois Power
21		Agency Act. For purposes of this Section, "Agency"
22		shall mean the Illinois Power Agency.
23		(ii) The long-term renewable resources planning
24		process shall be conducted as follows:
25		(A) Electric utilities shall provide a range
26		of load forecasts to the Illinois Power Agency

SB0025 Enrolled - 799 - LRB104 07069 BAB 17106 b
1		within 45 days of the Agency's request for
2		forecasts, which request shall specify the length
3		and conditions for the forecasts including, but
4		not limited to, the quantity of distributed
5		generation expected to be interconnected for each
6		year.
7		(B) The Agency shall publish for comment the
8		initial long-term renewable resources procurement
9		plan no later than 120 days after the effective
10		date of this amendatory Act of the 99th General
11		Assembly and shall review, and may revise, the
12		plan at least every 2 years thereafter. To the
13		extent practicable, the Agency shall review and
14		propose any revisions to the long-term renewable
15		energy resources procurement plan in conjunction
16		with the Agency's other planning and approval
17		processes conducted under this Section. Plans may
18		be released on separate dates, but the Agency
19		shall, to the extent practicable, release both
20		plans across a 30-day period. The initial
21		long-term renewable resources procurement plan
22		shall:
23		(aa) Identify the procurement programs and
24		competitive procurement events consistent with
25		the applicable requirements of the Illinois
26		Power Agency Act and shall be designed to

SB0025 Enrolled - 800 - LRB104 07069 BAB 17106 b
1		achieve the goals set forth in subsection (c)
2		of Section 1-75 of that Act.
3		(bb) Include a schedule for procurements
4		for renewable energy credits from
5		utility-scale wind projects, utility-scale
6		solar projects, and brownfield site
7		photovoltaic projects consistent with
8		subparagraph (G) of paragraph (1) of
9		subsection (c) of Section 1-75 of the Illinois
10		Power Agency Act.
11		(cc) Identify the process whereby the
12		Agency will submit to the Commission for
13		review and approval the proposed contracts to
14		implement the programs required by such plan.
15		If so authorized by the Commission in its
16		order approving the procurement plan, the
17		procurement plan shall provide that small
18		multi-jurisdictional electric utilities that, on
19		December 31, 2005, served fewer than 100,000
20		customers in Illinois shall, in lieu of serving as
21		counterparties to contracts for the delivery of
22		renewable energy credits, instead provide an
23		amount equivalent to the contracts for the
24		delivery of renewable energy credits in
25		collections to utilities that served at least
26		100,000 customers in Illinois as a compliance

SB0025 Enrolled - 801 - LRB104 07069 BAB 17106 b
1		payment for the procurement of additional
2		renewable energy credits to satisfy that small
3		multi-jurisdictional electric utility's
4		obligation for compliance with the goals set forth
5		in subsection (c) of Section 1-75 of the Illinois
6		Power Agency Act. This authorization may include
7		the transfer of existing contract obligations.
8		Copies of the initial long-term renewable
9		resources procurement plan and all subsequent
10		revisions shall be posted and made publicly
11		available on the Agency's and Commission's
12		websites, and copies shall also be provided to
13		each affected electric utility. An affected
14		utility and other interested parties shall have 45
15		days following the date of posting to provide
16		comment to the Agency on the initial long-term
17		renewable resources procurement plan and all
18		subsequent revisions. All comments submitted to
19		the Agency shall be specific, supported by data or
20		other detailed analyses, and, if objecting to all
21		or a portion of the procurement plan, accompanied
22		by specific alternative wording or proposals. All
23		comments shall be posted on the Agency's and
24		Commission's websites. During this 45-day comment
25		period, the Agency shall hold at least one virtual
26		or in-person public hearing for within each

SB0025 Enrolled - 802 - LRB104 07069 BAB 17106 b
1		utility's service area that is subject to the
2		requirements of this paragraph (5) for the purpose
3		of receiving public comment. Within 21 days
4		following the end of the 45-day review period, the
5		Agency may revise the long-term renewable
6		resources procurement plan based on the comments
7		received and shall file the plan with the
8		Commission for review and approval.
9		(C) Within 14 days after the filing of the
10		initial long-term renewable resources procurement
11		plan or any subsequent revisions, any person
12		objecting to the plan may file an objection with
13		the Commission. Within 21 days after the filing of
14		the plan, the Commission shall determine whether a
15		hearing is necessary. The Commission shall enter
16		its order confirming or modifying the initial
17		long-term renewable resources procurement plan or
18		any subsequent revisions within 120 days after the
19		filing of the plan by the Illinois Power Agency.
20		(D) The Commission shall approve the initial
21		long-term renewable resources procurement plan and
22		any subsequent revisions, including expressly the
23		forecast used in the plan and taking into account
24		that funding will be limited to the amount of
25		revenues actually collected by the utilities, if
26		the Commission determines that the plan will

SB0025 Enrolled - 803 - LRB104 07069 BAB 17106 b
1		reasonably and prudently accomplish the
2		requirements of Section 1-56 and subsection (c) of
3		Section 1-75 of the Illinois Power Agency Act. The
4		Commission shall also approve the process for the
5		submission, review, and approval of the proposed
6		contracts to procure renewable energy credits or
7		implement the programs authorized by the
8		Commission pursuant to a long-term renewable
9		resources procurement plan approved under this
10		Section.
11		In approving any long-term renewable resources
12		procurement plan after the effective date of this
13		amendatory Act of the 102nd General Assembly, the
14		Commission shall approve or modify the Agency's
15		proposal for minimum equity standards pursuant to
16		subsection (c-10) of Section 1-75 of the Illinois
17		Power Agency Act. The Commission shall consider
18		any analysis performed by the Agency in developing
19		its proposal, including past performance,
20		availability of equity eligible contractors, and
21		availability of equity eligible persons at the
22		time the long-term renewable resources procurement
23		plan is approved.
24		(iii) The Agency or third parties contracted by
25		the Agency shall implement all programs authorized by
26		the Commission in an approved long-term renewable

SB0025 Enrolled - 804 - LRB104 07069 BAB 17106 b
1		resources procurement plan without further review and
2		approval by the Commission. Third parties shall not
3		begin implementing any programs or receive any payment
4		under this Section until the Commission has approved
5		the contract or contracts under the process authorized
6		by the Commission in item (D) of subparagraph (ii) of
7		paragraph (5) of this subsection (b) and the third
8		party and the Agency or utility, as applicable, have
9		executed the contract. For those renewable energy
10		credits subject to procurement through a competitive
11		bid process under the plan or under the initial
12		forward procurements for wind and solar resources
13		described in subparagraph (G) of paragraph (1) of
14		subsection (c) of Section 1-75 of the Illinois Power
15		Agency Act, the Agency shall follow the procurement
16		process specified in the provisions relating to
17		electricity procurement in subsections (e) through (i)
18		of this Section.
19		(iv) An electric utility shall recover its costs
20		associated with the procurement of renewable energy
21		credits under this Section and pursuant to subsection
22		(c-5) of Section 1-75 of the Illinois Power Agency Act
23		through an automatic adjustment clause tariff under
24		subsection (k) or a tariff pursuant to subsection
25		(i-5), as applicable, of Section 16-108 of this Act. A
26		utility shall not be required to advance any payment

SB0025 Enrolled - 805 - LRB104 07069 BAB 17106 b
1		or pay any amounts under this Section that exceed the
2		actual amount of revenues collected by the utility
3		under paragraph (6) of subsection (c) of Section 1-75
4		of the Illinois Power Agency Act, subsection (c-5) of
5		Section 1-75 of the Illinois Power Agency Act, and
6		subsection (k) or subsection (i-5), as applicable, of
7		Section 16-108 of this Act, and contracts executed
8		under this Section shall expressly incorporate this
9		limitation.
10		(v) For the public interest, safety, and welfare,
11		the Agency and the Commission may adopt rules to carry
12		out the provisions of this Section on an emergency
13		basis immediately following the effective date of this
14		amendatory Act of the 99th General Assembly.
15		(vi) On or before July 1 of each year, the
16		Commission shall hold an informal hearing for the
17		purpose of receiving comments on the prior year's
18		procurement process and any recommendations for
19		change.
20		(6) Energy Storage System Resources Procurement Plan.
21		The Agency shall prepare an energy storage system
22		resources procurement plan for the procurement of energy
23		storage system resources in compliance with this Section
24		and subsection (d-20) of Section 1-75 of the Illinois
25		Power Agency Act.
26		(i) The initial energy storage system resources

SB0025 Enrolled - 806 - LRB104 07069 BAB 17106 b
1		procurement plan and all subsequent revisions shall be
2		subject to review and approval by the Commission. For
3		the purposes of this paragraph (6), "delivery year"
4		has the meaning given to that term in Section 1-10 of
5		the Illinois Power Agency Act, and "Agency" means the
6		Illinois Power Agency.
7		(ii) The energy storage system resources
8		procurement planning process shall be conducted as
9		follows:
10		(A) The Agency shall publish for comment the
11		initial energy storage system resources
12		procurement plan no later than June 1, 2027 and
13		may revise the plan at least every 2 years
14		thereafter. To the extent practicable, the Agency
15		shall review and propose any revisions to the
16		energy storage system resources procurement plan
17		in conjunction with the Agency's long-term
18		renewable resources procurement plan. The initial
19		energy storage system resources plan shall:
20		(aa) include a schedule for procurements
21		for energy storage system resources consistent
22		with subsection (d-20) of Section 1-75 of the
23		Illinois Power Agency Act and the integrated
24		resource planning process outlined in Section
25		16-202; and
26		(bb) identify the process whereby the

SB0025 Enrolled - 807 - LRB104 07069 BAB 17106 b
1		Agency will submit to the Commission for
2		review and approval the proposed contracts to
3		implement the programs required by the plan.
4		Copies of the initial energy storage system
5		resources procurement plan and all subsequent
6		revisions shall be posted and made publicly
7		available on the Agency's and Commission's
8		websites, and copies shall also be provided to
9		each affected electric utility. An affected
10		utility and other interested parties shall have 45
11		days after the date of posting to provide comment
12		to the Agency on the initial storage system
13		resources procurement plan and all subsequent
14		revisions. All comments shall be posted on the
15		Agency's and the Commission's websites.
16		(B) The Commission shall approve the initial
17		energy storage system resources procurement plan
18		and any subsequent revisions if the Commission
19		determines that the plan will reasonably and
20		prudently accomplish the requirements of
21		subsection (d-20) of Section 1-75 of the Illinois
22		Power Agency Act. The Commission shall also
23		approve the process for the submission, review,
24		and approval of the proposed contracts to procure
25		energy storage system resources or implement the
26		programs authorized by the Commission pursuant to

SB0025 Enrolled - 808 - LRB104 07069 BAB 17106 b
1		an energy storage system resources procurement
2		plan approved under this Section.
3		(iii) The Agency or third parties contracted by
4		the Agency shall implement all programs authorized by
5		the Commission in an approved energy storage system
6		resources procurement plan without further review and
7		approval by the Commission. Third parties shall not
8		begin implementing any programs or receive any payment
9		under this Section until the Commission has approved a
10		contract under the energy storage system resources
11		procurement process under this Section.
12		(iv) An electric utility shall recover its prudent
13		and reasonable costs associated with the procurement
14		of energy storage system resources procurements under
15		this Section and under subsection (d-20) of Section
16		1-75 of the Illinois Power Agency Act through an
17		automatic adjustment clause tariff under subsection
18		(k) of Section 16-108.
19		(b-5) An electric utility that as of January 1, 2019
20		served more than 300,000 retail customers in this State shall
21		purchase renewable energy credits from new renewable energy
22		facilities constructed at or adjacent to the sites of
23		coal-fueled electric generating facilities in this State in
24		accordance with subsection (c-5) of Section 1-75 of the
25		Illinois Power Agency Act and shall purchase energy storage
26		credits, or other services as applicable, for energy storage

SB0025 Enrolled - 809 - LRB104 07069 BAB 17106 b
1		system resources in accordance with subsection (d-20) of
2		Section 1-75 of the Illinois Power Agency Act. Except as
3		expressly provided in this Section, the plans and procedures
4		for such procurements shall not be included in the procurement
5		plans provided for in this Section, but rather shall be
6		conducted and implemented solely in accordance with subsection
7		(c-5) of Section 1-75 of the Illinois Power Agency Act.
8		(b-10) Beginning with the procurement plan for the
9		delivery year commencing on June 1, 2027, in recognition of
10		the potential need to facilitate additional supply to address
11		any resource adequacy challenges through a stable and
12		competitively neutral cost allocation mechanism, upon an
13		identification of need by the Commission in the resource
14		adequacy report prepared pursuant to subsection (o) of Section
15		9.15 of the Environmental Protection Act, and as such need is
16		updated by the integrated resource planning process outlined
17		in subsection (b), the procurement plan shall also include the
18		procurement of energy, capacity, environmental attributes,
19		resource adequacy attributes, or some combination thereof
20		intended to serve all retail customers. Any procurements
21		proposed under this subsection (b-10) shall feature long-term
22		contracts, shall be structured to facilitate new and additive
23		supply resources, and shall be sized to ensure that the
24		substantial majority of any load-serving entity's supply
25		portfolio is not composed of contracts awarded under this
26		subsection (b-10). Any procurement should consider the value

SB0025 Enrolled - 810 - LRB104 07069 BAB 17106 b
1		of higher capacity resources that aid in resource adequacy.
2		The Agency shall propose contract structures that do not
3		create contractual obligations on utilities that are not
4		contingent on full and timely cost recovery, that avoid
5		negative financial impacts on the utilities, and that are
6		implemented through contracts that are agreed upon by the
7		utilities.
8		(1) Facilities eligible for long-term contracts under
9		this subsection (b-10) must be new clean energy resources,
10		as defined in Section 1-10 of the Illinois Power Agency
11		Act, including clean generation associated high voltage
12		direct current transmission facilities, and must qualify
13		as an accredited capacity resource within the service
14		areas of PJM Interconnection, LLC, or Midcontinent
15		Independent System Operator, Inc. For purposes of this
16		subsection (b-10), "new" means energized on or after the
17		effective date of this amendatory Act of the 104th General
18		Assembly.
19		(2) Contracts may take the form of a sourcing
20		agreement, power purchase agreement, or other instrument
21		as determined by the Commission in approving the plan, and
22		may feature fixed or variable pricing structures,
23		including utilization of a contract for differences in
24		pricing structure. Contracts may feature both electric
25		utilities and alternative retail electric suppliers as
26		counterparties. In approving the contract structure

SB0025 Enrolled - 811 - LRB104 07069 BAB 17106 b
1		utilized for any contract awards made pursuant to this
2		subsection (b-10), the Commission shall prioritize
3		structures that ensure stable, reliable, and competitively
4		neutral allocations of costs and responsibilities.
5		(3) Purchases made under contracts awarded through
6		this subsection (b-10) shall be funded in a competitively
7		neutral manner as determined by the Commission in
8		approving the plan. To meet contract obligations, the
9		Commission may order collections from all retail customers
10		or from all load-serving entities, including alternative
11		retail electric suppliers as defined in Section 16-102 of
12		this Act, as a means of ensuring a fair and competitively
13		neutral allocation of contract costs. In establishing
14		collections, the Agency may propose and the Commission may
15		approve adjustments for load-serving entities that have
16		contracts entered into before the effective date of this
17		amendatory Act of the 104th General Assembly for energy,
18		capacity, or environmental attributes to ensure customers
19		are not double-billed for the same service.
20		(4) The Agency may propose and the Commission may
21		approve additional terms, conditions, and requirements
22		applicable to this procurement process through development
23		and approval of the Agency's annual electricity
24		procurement plan.
25		(5) The manner and form for developing contracts,
26		qualifying potential counterparties, and awarding

SB0025 Enrolled - 812 - LRB104 07069 BAB 17106 b
1		contracts shall be proposed as part of the annual
2		electricity procurement plan described in this subsection
3		(b-10). However, to the extent practicable, the proposed
4		approach for contract development and award should
5		endeavor to follow the provisions of subsections (c) and
6		(e) through (i) of this Section.
7		(6) As further outlined in Section 16-115A, compliance
8		with any procurement process proposed under this
9		subsection (b-10) shall be considered a condition of
10		service for alternative retail electric suppliers.
11		(c) The provisions of this subsection (c) shall not apply
12		to procurements conducted pursuant to subsection (c-5) of
13		Section 1-75 of the Illinois Power Agency Act. However, the
14		Agency may retain a procurement administrator to assist the
15		Agency in planning and carrying out the procurement events and
16		implementing the other requirements specified in such
17		subsection (c-5) of Section 1-75 of the Illinois Power Agency
18		Act, with the costs incurred by the Agency for the procurement
19		administrator to be recovered through fees charged to
20		applicants for selection to sell and deliver renewable energy
21		credits to electric utilities pursuant to subsection (c-5) of
22		Section 1-75 of the Illinois Power Agency Act. The procurement
23		process set forth in Section 1-75 of the Illinois Power Agency
24		Act and subsection (e) of this Section shall be administered
25		by a procurement administrator and monitored by a procurement
26		monitor.

SB0025 Enrolled - 813 - LRB104 07069 BAB 17106 b
1		(1) The procurement administrator shall:
2		(i) design the final procurement process in
3		accordance with Section 1-75 of the Illinois Power
4		Agency Act and subsection (e) of this Section
5		following Commission approval of the procurement plan;
6		(ii) develop benchmarks in accordance with
7		subsection (e)(3) to be used to evaluate bids; these
8		benchmarks shall be submitted to the Commission for
9		review and approval on a confidential basis prior to
10		the procurement event;
11		(iii) serve as the interface between the electric
12		utility and suppliers;
13		(iv) manage the bidder pre-qualification and
14		registration process;
15		(v) obtain the electric utilities' agreement to
16		the final form of all supply contracts and credit
17		collateral agreements;
18		(vi) administer the request for proposals process;
19		(vii) have the discretion to negotiate to
20		determine whether bidders are willing to lower the
21		price of bids that meet the benchmarks approved by the
22		Commission; any post-bid negotiations with bidders
23		shall be limited to price only and shall be completed
24		within 24 hours after opening the sealed bids and
25		shall be conducted in a fair and unbiased manner; in
26		conducting the negotiations, there shall be no

SB0025 Enrolled - 814 - LRB104 07069 BAB 17106 b
1		disclosure of any information derived from proposals
2		submitted by competing bidders; if information is
3		disclosed to any bidder, it shall be provided to all
4		competing bidders;
5		(viii) maintain confidentiality of supplier and
6		bidding information in a manner consistent with all
7		applicable laws, rules, regulations, and tariffs;
8		(ix) submit a confidential report to the
9		Commission recommending acceptance or rejection of
10		bids;
11		(x) notify the utility of contract counterparties
12		and contract specifics; and
13		(xi) administer related contingency procurement
14		events.
15		(2) The procurement monitor, who shall be retained by
16		the Commission, shall:
17		(i) monitor interactions among the procurement
18		administrator, suppliers, and utility;
19		(ii) monitor and report to the Commission on the
20		progress of the procurement process;
21		(iii) provide an independent confidential report
22		to the Commission regarding the results of the
23		procurement event;
24		(iv) assess compliance with the procurement plans
25		approved by the Commission for each utility that on
26		December 31, 2005 provided electric service to at

SB0025 Enrolled - 815 - LRB104 07069 BAB 17106 b
1		least 100,000 customers in Illinois and for each small
2		multi-jurisdictional utility that on December 31, 2005
3		served less than 100,000 customers in Illinois;
4		(v) preserve the confidentiality of supplier and
5		bidding information in a manner consistent with all
6		applicable laws, rules, regulations, and tariffs;
7		(vi) provide expert advice to the Commission and
8		consult with the procurement administrator regarding
9		issues related to procurement process design, rules,
10		protocols, and policy-related matters; and
11		(vii) consult with the procurement administrator
12		regarding the development and use of benchmark
13		criteria, standard form contracts, credit policies,
14		and bid documents.
15		(d) Except as provided in subsection (j), the planning
16		process shall be conducted as follows:
17		(1) Beginning in 2008, each Illinois utility procuring
18		power pursuant to this Section shall annually provide a
19		range of load forecasts to the Illinois Power Agency by
20		July 15 of each year, or such other date as may be required
21		by the Commission or Agency. The load forecasts shall
22		cover the 5-year procurement planning period for the next
23		procurement plan and shall include hourly data
24		representing a high-load, low-load, and expected-load
25		scenario for the load of those retail customers included
26		in the plan's electric supply service requirements. The

SB0025 Enrolled - 816 - LRB104 07069 BAB 17106 b
1		utility shall provide supporting data and assumptions for
2		each of the scenarios.
3		(2) Beginning in 2008, the Illinois Power Agency shall
4		prepare a procurement plan by August 15th of each year, or
5		such other date as may be required by the Commission. The
6		procurement plan shall identify the portfolio of
7		demand-response and power and energy products to be
8		procured. Cost-effective demand-response measures shall be
9		procured as set forth in item (iii) of subsection (b) of
10		this Section. Copies of the procurement plan shall be
11		posted and made publicly available on the Agency's and
12		Commission's websites, and copies shall also be provided
13		to each affected electric utility. An affected utility
14		shall have 30 days following the date of posting to
15		provide comment to the Agency on the procurement plan.
16		Other interested entities also may comment on the
17		procurement plan. All comments submitted to the Agency
18		shall be specific, supported by data or other detailed
19		analyses, and, if objecting to all or a portion of the
20		procurement plan, accompanied by specific alternative
21		wording or proposals. All comments shall be posted on the
22		Agency's and Commission's websites. During this 30-day
23		comment period, the Agency shall hold at least one virtual
24		or in-person public hearing for within each utility's
25		service area for the purpose of receiving public comment
26		on the procurement plan. Within 14 days following the end

SB0025 Enrolled - 817 - LRB104 07069 BAB 17106 b
1		of the 30-day review period, the Agency shall revise the
2		procurement plan as necessary based on the comments
3		received and file the procurement plan with the Commission
4		and post the procurement plan on the websites.
5		(3) Within 5 days after the filing of the procurement
6		plan, any person objecting to the procurement plan shall
7		file an objection with the Commission. Within 10 days
8		after the filing, the Commission shall determine whether a
9		hearing is necessary. The Commission shall enter its order
10		confirming or modifying the procurement plan within 90
11		days after the filing of the procurement plan by the
12		Illinois Power Agency.
13		(4) The Commission shall approve the procurement plan,
14		including expressly the forecast used in the procurement
15		plan, if the Commission determines that it will 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.
20		(4.5) The Commission shall review the Agency's
21		recommendations for the selection of applicants to enter
22		into long-term contracts for the sale and delivery of
23		renewable energy credits from new renewable energy
24		facilities to be constructed at or adjacent to the sites
25		of coal-fueled electric generating facilities in this
26		State in accordance with the provisions of subsection

SB0025 Enrolled - 818 - LRB104 07069 BAB 17106 b
1		(c-5) of Section 1-75 of the Illinois Power Agency Act,
2		and shall approve the Agency's recommendations if the
3		Commission determines that the applicants recommended by
4		the Agency for selection, the proposed new renewable
5		energy facilities to be constructed, the amounts of
6		renewable energy credits to be delivered pursuant to the
7		contracts, and the other terms of the contracts, are
8		consistent with the requirements of subsection (c-5) of
9		Section 1-75 of the Illinois Power Agency Act.
10		(e) The procurement process shall include each of the
11		following components:
12		(1) Solicitation, pre-qualification, and registration
13		of bidders. The procurement administrator shall
14		disseminate information to potential bidders to promote a
15		procurement event, notify potential bidders that the
16		procurement administrator may enter into a post-bid price
17		negotiation with bidders that meet the applicable
18		benchmarks, provide supply requirements, and otherwise
19		explain the competitive procurement process. In addition
20		to such other publication as the procurement administrator
21		determines is appropriate, this information shall be
22		posted on the Illinois Power Agency's and the Commission's
23		websites. The procurement administrator shall also
24		administer the prequalification process, including
25		evaluation of credit worthiness, compliance with
26		procurement rules, and agreement to the standard form

SB0025 Enrolled - 819 - LRB104 07069 BAB 17106 b
1		contract developed pursuant to paragraph (2) of this
2		subsection (e). The procurement administrator shall then
3		identify and register bidders to participate in the
4		procurement event.
5		(2) Standard contract forms and credit terms and
6		instruments. The procurement administrator, in
7		consultation with the utilities, the Commission, and other
8		interested parties and subject to Commission oversight,
9		shall develop and provide standard contract forms for the
10		supplier contracts that meet generally accepted industry
11		practices. Standard credit terms and instruments that meet
12		generally accepted industry practices shall be similarly
13		developed. The procurement administrator shall make
14		available to the Commission all written comments it
15		receives on the contract forms, credit terms, or
16		instruments. If the procurement administrator cannot reach
17		agreement with the applicable electric utility as to the
18		contract terms and conditions, the procurement
19		administrator must notify the Commission of any disputed
20		terms and the Commission shall resolve the dispute. The
21		terms of the contracts shall not be subject to negotiation
22		by winning bidders, and the bidders must agree to the
23		terms of the contract in advance so that winning bids are
24		selected solely on the basis of price.
25		(3) Establishment of a market-based price benchmark.
26		As part of the development of the procurement process, the

SB0025 Enrolled - 820 - LRB104 07069 BAB 17106 b
1		procurement administrator, in consultation with the
2		Commission staff, Agency staff, and the procurement
3		monitor, shall establish benchmarks for evaluating the
4		final prices in the contracts for each of the products
5		that will be procured through the procurement process. The
6		benchmarks shall be based on price data for similar
7		products for the same delivery period and same delivery
8		hub, or other delivery hubs after adjusting for that
9		difference. The price benchmarks may also be adjusted to
10		take into account differences between the information
11		reflected in the underlying data sources and the specific
12		products and procurement process being used to procure
13		power for the Illinois utilities. The benchmarks shall be
14		confidential but shall be provided to, and will be subject
15		to Commission review and approval, prior to a procurement
16		event.
17		(4) Request for proposals competitive procurement
18		process. The procurement administrator shall design and
19		issue a request for proposals to supply electricity in
20		accordance with each utility's procurement plan, as
21		approved by the Commission. The request for proposals
22		shall set forth a procedure for sealed, binding commitment
23		bidding with pay-as-bid settlement, and provision for
24		selection of bids on the basis of price.
25		(5) A plan for implementing contingencies in the event
26		of supplier default or failure of the procurement process

SB0025 Enrolled - 821 - LRB104 07069 BAB 17106 b
1		to fully meet the expected load requirement due to
2		insufficient supplier participation, Commission rejection
3		of results, or any other cause.
4		(i) Event of supplier default: In the event of
5		supplier default, the utility shall review the
6		contract of the defaulting supplier to determine if
7		the amount of supply is 200 megawatts or greater, and
8		if there are more than 60 days remaining of the
9		contract term. If both of these conditions are met,
10		and the default results in termination of the
11		contract, the utility shall immediately notify the
12		Illinois Power Agency that a request for proposals
13		must be issued to procure replacement power, and the
14		procurement administrator shall run an additional
15		procurement event. If the contracted supply of the
16		defaulting supplier is less than 200 megawatts or
17		there are less than 60 days remaining of the contract
18		term, the utility shall procure power and energy from
19		the applicable regional transmission organization
20		market, including ancillary services, capacity, and
21		day-ahead or real time energy, or both, for the
22		duration of the contract term to replace the
23		contracted supply; provided, however, that if a needed
24		product is not available through the regional
25		transmission organization market it shall be purchased
26		from the wholesale market.

SB0025 Enrolled - 822 - LRB104 07069 BAB 17106 b
1		(ii) Failure of the procurement process to fully
2		meet the expected load requirement: If the procurement
3		process fails to fully meet the expected load
4		requirement due to insufficient supplier participation
5		or due to a Commission rejection of the procurement
6		results, the procurement administrator, the
7		procurement monitor, and the Commission staff shall
8		meet within 10 days to analyze potential causes of low
9		supplier interest or causes for the Commission
10		decision. If changes are identified that would likely
11		result in increased supplier participation, or that
12		would address concerns causing the Commission to
13		reject the results of the prior procurement event, the
14		procurement administrator may implement those changes
15		and rerun the request for proposals process according
16		to a schedule determined by those parties and
17		consistent with Section 1-75 of the Illinois Power
18		Agency Act and this subsection. In any event, a new
19		request for proposals process shall be implemented by
20		the procurement administrator within 90 days after the
21		determination that the procurement process has failed
22		to fully meet the expected load requirement.
23		(iii) In all cases where there is insufficient
24		supply provided under contracts awarded through the
25		procurement process to fully meet the electric
26		utility's load requirement, the utility shall meet the

SB0025 Enrolled - 823 - LRB104 07069 BAB 17106 b
1		load requirement by procuring power and energy from
2		the applicable regional transmission organization
3		market, including ancillary services, capacity, and
4		day-ahead or real time energy, or both; provided,
5		however, that if a needed product is not available
6		through the regional transmission organization market
7		it shall be purchased from the wholesale market.
8		(6) The procurement processes described in this
9		subsection and in subsection (c-5) of Section 1-75 of the
10		Illinois Power Agency Act are exempt from the requirements
11		of the Illinois Procurement Code, pursuant to Section
12		20-10 of that Code.
13		(f) Within 2 business days after opening the sealed bids,
14		the procurement administrator shall submit a confidential
15		report to the Commission. The report shall contain the results
16		of the bidding for each of the products along with the
17		procurement administrator's recommendation for the acceptance
18		and rejection of bids based on the price benchmark criteria
19		and other factors observed in the process. The procurement
20		monitor also shall submit a confidential report to the
21		Commission within 2 business days after opening the sealed
22		bids. The report shall contain the procurement monitor's
23		assessment of bidder behavior in the process as well as an
24		assessment of the procurement administrator's compliance with
25		the procurement process and rules. The Commission shall review
26		the confidential reports submitted by the procurement

SB0025 Enrolled - 824 - LRB104 07069 BAB 17106 b
1		administrator and procurement monitor, and shall accept or
2		reject the recommendations of the procurement administrator
3		within 2 business days after receipt of the reports.
4		(g) Within 3 business days after the Commission decision
5		approving the results of a procurement event, the utility
6		shall enter into binding contractual arrangements with the
7		winning suppliers using the standard form contracts; except
8		that the utility shall not be required either directly or
9		indirectly to execute the contracts if a tariff that is
10		consistent with subsection (l) of this Section has not been
11		approved and placed into effect for that utility.
12		(h) For the procurement of standard wholesale products,
13		the names of the successful bidders and the load weighted
14		average of the winning bid prices for each contract type and
15		for each contract term shall be made available to the public at
16		the time of Commission approval of a procurement event. For
17		procurements conducted to meet the requirements of subsection
18		(b) of Section 1-56 or subsection (c) of Section 1-75 of the
19		Illinois Power Agency Act governed by the provisions of this
20		Section, the address and nameplate capacity of the new
21		renewable energy generating facility proposed by a winning
22		bidder shall also be made available to the public at the time
23		of Commission approval of a procurement event, along with the
24		business address and contact information for any winning
25		bidder. An estimate or approximation of the nameplate capacity
26		of the new renewable energy generating facility may be

SB0025 Enrolled - 825 - LRB104 07069 BAB 17106 b
1		disclosed if necessary to protect the confidentiality of
2		individual bid prices.
3		The Commission, the procurement monitor, the procurement
4		administrator, the Illinois Power Agency, and all participants
5		in the procurement process shall maintain the confidentiality
6		of all other supplier and bidding information in a manner
7		consistent with all applicable laws, rules, regulations, and
8		tariffs. Confidential information, including the confidential
9		reports submitted by the procurement administrator and
10		procurement monitor pursuant to subsection (f) of this
11		Section, shall not be made publicly available and shall not be
12		discoverable by any party in any proceeding, absent a
13		compelling demonstration of need, nor shall those reports be
14		admissible in any proceeding other than one for law
15		enforcement purposes.
16		For procurements conducted to meet the requirements of
17		subsection (b) of Section 1-56 or subsection (c) of Section
18		1-75 of the Illinois Power Agency Act, the Illinois Power
19		Agency may release aggregated information related to
20		participation levels across product types and the basis of
21		rejection for non-accepted bids if the Commission, the
22		procurement monitor, the procurement administrator, and the
23		Illinois Power Agency determine that the release of this
24		information would not result in the disclosure of confidential
25		bid information or negatively impact the competitiveness of
26		future renewable energy credit procurements. The Agency may

SB0025 Enrolled - 826 - LRB104 07069 BAB 17106 b
1		also release information about the development status of new
2		renewable energy projects under contract and project-specific
3		information about renewable energy credit delivery quantities
4		for projects under contract if the Commission, the procurement
5		monitor, the procurement administrator, and the Illinois Power
6		Agency determine that the release of this information would
7		not result in the disclosure of confidential bid information
8		or negatively impact the competitiveness of future renewable
9		energy credit procurements.
10		(i) Within 2 business days after a Commission decision
11		approving the results of a procurement event or such other
12		date as may be required by the Commission from time to time,
13		the utility shall file for informational purposes with the
14		Commission its actual or estimated retail supply charges, as
15		applicable, by customer supply group reflecting the costs
16		associated with the procurement and computed in accordance
17		with the tariffs filed pursuant to subsection (l) of this
18		Section and approved by the Commission.
19		(j) Within 60 days following August 28, 2007 (the
20		effective date of Public Act 95-481), each electric utility
21		that on December 31, 2005 provided electric service to at
22		least 100,000 customers in Illinois shall prepare and file
23		with the Commission an initial procurement plan, which shall
24		conform in all material respects to the requirements of the
25		procurement plan set forth in subsection (b); provided,
26		however, that the Illinois Power Agency Act shall not apply to

SB0025 Enrolled - 827 - LRB104 07069 BAB 17106 b
1		the initial procurement plan prepared pursuant to this
2		subsection. The initial procurement plan shall identify the
3		portfolio of power and energy products to be procured and
4		delivered for the period June 2008 through May 2009, and shall
5		identify the proposed procurement administrator, who shall
6		have the same experience and expertise as is required of a
7		procurement administrator hired pursuant to Section 1-75 of
8		the Illinois Power Agency Act. Copies of the procurement plan
9		shall be posted and made publicly available on the
10		Commission's website. The initial procurement plan may include
11		contracts for renewable resources that extend beyond May 2009.
12		(i) Within 14 days following filing of the initial
13		procurement plan, any person may file a detailed objection
14		with the Commission contesting the procurement plan
15		submitted by the electric utility. All objections to the
16		electric utility's plan shall be specific, supported by
17		data or other detailed analyses. The electric utility may
18		file a response to any objections to its procurement plan
19		within 7 days after the date objections are due to be
20		filed. Within 7 days after the date the utility's response
21		is due, the Commission shall determine whether a hearing
22		is necessary. If it determines that a hearing is
23		necessary, it shall require the hearing to be completed
24		and issue an order on the procurement plan within 60 days
25		after the filing of the procurement plan by the electric
26		utility.

SB0025 Enrolled - 828 - LRB104 07069 BAB 17106 b
1		(ii) The order shall approve or modify the procurement
2		plan, approve an independent procurement administrator,
3		and approve or modify the electric utility's tariffs that
4		are proposed with the initial procurement plan. The
5		Commission shall approve the procurement plan if the
6		Commission determines that it will ensure adequate,
7		reliable, affordable, efficient, and environmentally
8		sustainable electric service at the lowest total cost over
9		time, taking into account any benefits of price stability.
10		(k) (Blank).
11		(k-5) (Blank).
12		(l) An electric utility shall recover its costs incurred
13		under this Section and subsection (c-5) of Section 1-75 of the
14		Illinois Power Agency Act, including, but not limited to, the
15		costs of procuring power and energy demand-response resources
16		under this Section and its costs for purchasing renewable
17		energy credits pursuant to subsection (c-5) of Section 1-75 of
18		the Illinois Power Agency Act. The utility shall file with the
19		initial procurement plan its proposed tariffs through which
20		its costs of procuring power that are incurred pursuant to a
21		Commission-approved procurement plan and those other costs
22		identified in this subsection (l), will be recovered. The
23		tariffs shall include a formula rate or charge designed to
24		pass through both the costs incurred by the utility in
25		procuring a supply of electric power and energy for the
26		applicable customer classes with no mark-up or return on the

SB0025 Enrolled - 829 - LRB104 07069 BAB 17106 b
1		price paid by the utility for that supply, plus any just and
2		reasonable costs that the utility incurs in arranging and
3		providing for the supply of electric power and energy. The
4		formula rate or charge shall also contain provisions that
5		ensure that its application does not result in over or under
6		recovery due to changes in customer usage and demand patterns,
7		and that provide for the correction, on at least an annual
8		basis, of any accounting errors that may occur. A utility
9		shall recover through the tariff all reasonable costs incurred
10		to implement or comply with any procurement plan that is
11		developed and put into effect pursuant to Section 1-75 of the
12		Illinois Power Agency Act and this Section, and for the
13		procurement of renewable energy credits pursuant to subsection
14		(c-5) of Section 1-75 of the Illinois Power Agency Act,
15		including any fees assessed by the Illinois Power Agency,
16		costs associated with load balancing, and contingency plan
17		costs. The electric utility shall also recover its full costs
18		of procuring electric supply for which it contracted before
19		the effective date of this Section in conjunction with the
20		provision of full requirements service under fixed-price
21		bundled service tariffs subsequent to December 31, 2006. All
22		such costs shall be deemed to have been prudently incurred.
23		The pass-through tariffs that are filed and approved pursuant
24		to this Section shall not be subject to review under, or in any
25		way limited by, Section 16-111(i) of this Act. All of the costs
26		incurred by the electric utility associated with the purchase

SB0025 Enrolled - 830 - LRB104 07069 BAB 17106 b
1		of zero emission credits in accordance with subsection (d-5)
2		of Section 1-75 of the Illinois Power Agency Act, all costs
3		incurred by the electric utility associated with the purchase
4		of carbon mitigation credits in accordance with subsection
5		(d-10) of Section 1-75 of the Illinois Power Agency Act, and,
6		beginning June 1, 2017, all of the costs incurred by the
7		electric utility associated with the purchase of renewable
8		energy resources in accordance with Sections 1-56 and 1-75 of
9		the Illinois Power Agency Act, and all of the costs incurred by
10		the electric utility in purchasing renewable energy credits in
11		accordance with subsection (c-5) of Section 1-75 of the
12		Illinois Power Agency Act, shall be recovered through the
13		electric utility's tariffed charges applicable to all of its
14		retail customers, as specified in subsection (k) or subsection
15		(i-5), as applicable, of Section 16-108 of this Act, and shall
16		not be recovered through the electric utility's tariffed
17		charges for electric power and energy supply to its eligible
18		retail customers.
19		(m) The Commission has the authority to adopt rules to
20		carry out the provisions of this Section. For the public
21		interest, safety, and welfare, the Commission also has
22		authority to adopt rules to carry out the provisions of this
23		Section on an emergency basis immediately following August 28,
24		2007 (the effective date of Public Act 95-481).
25		(n) Notwithstanding any other provision of this Act, any
26		affiliated electric utilities that submit a single procurement

SB0025 Enrolled - 831 - LRB104 07069 BAB 17106 b
1		plan covering their combined needs may procure for those
2		combined needs in conjunction with that plan, and may enter
3		jointly into power supply contracts, purchases, and other
4		procurement arrangements, and allocate capacity and energy and
5		cost responsibility therefor among themselves in proportion to
6		their requirements.
7		(o) On or before June 1 of each year, the Commission shall
8		hold an informal hearing for the purpose of receiving comments
9		on the prior year's procurement process and any
10		recommendations for change.
11		(p) An electric utility subject to this Section may
12		propose to invest, lease, own, or operate an electric
13		generation facility as part of its procurement plan, provided
14		the utility demonstrates that such facility is the least-cost
15		option to provide electric service to those retail customers
16		included in the plan's electric supply service requirements.
17		If the facility is shown to be the least-cost option and is
18		included in a procurement plan prepared in accordance with
19		Section 1-75 of the Illinois Power Agency Act and this
20		Section, then the electric utility shall make a filing
21		pursuant to Section 8-406 of this Act, and may request of the
22		Commission any statutory relief required thereunder. If the
23		Commission grants all of the necessary approvals for the
24		proposed facility, such supply shall thereafter be considered
25		as a pre-existing contract under subsection (b) of this
26		Section. The Commission shall in any order approving a

SB0025 Enrolled - 832 - LRB104 07069 BAB 17106 b
1		proposal under this subsection specify how the utility will
2		recover the prudently incurred costs of investing in, leasing,
3		owning, or operating such generation facility through just and
4		reasonable rates charged to those retail customers included in
5		the plan's electric supply service requirements. Cost recovery
6		for facilities included in the utility's procurement plan
7		pursuant to this subsection shall not be subject to review
8		under or in any way limited by the provisions of Section
9		16-111(i) of this Act. Nothing in this Section is intended to
10		prohibit a utility from filing for a fuel adjustment clause as
11		is otherwise permitted under Section 9-220 of this Act.
12		(q) If the Illinois Power Agency filed with the
13		Commission, under Section 16-111.5 of this Act, its proposed
14		procurement plan for the period commencing June 1, 2017, and
15		the Commission has not yet entered its final order approving
16		the plan on or before the effective date of this amendatory Act
17		of the 99th General Assembly, then the Illinois Power Agency
18		shall file a notice of withdrawal with the Commission, after
19		the effective date of this amendatory Act of the 99th General
20		Assembly, to withdraw the proposed procurement of renewable
21		energy resources to be approved under the plan, other than the
22		procurement of renewable energy credits from distributed
23		renewable energy generation devices using funds previously
24		collected from electric utilities' retail customers that take
25		service pursuant to electric utilities' hourly pricing tariff
26		or tariffs and, for an electric utility that serves less than

SB0025 Enrolled - 833 - LRB104 07069 BAB 17106 b
1		100,000 retail customers in the State, other than the
2		procurement of renewable energy credits from distributed
3		renewable energy generation devices. Upon receipt of the
4		notice, the Commission shall enter an order that approves the
5		withdrawal of the proposed procurement of renewable energy
6		resources from the plan. The initially proposed procurement of
7		renewable energy resources shall not be approved or be the
8		subject of any further hearing, investigation, proceeding, or
9		order of any kind.
10		This amendatory Act of the 99th General Assembly preempts
11		and supersedes any order entered by the Commission that
12		approved the Illinois Power Agency's procurement plan for the
13		period commencing June 1, 2017, to the extent it is
14		inconsistent with the provisions of this amendatory Act of the
15		99th General Assembly. To the extent any previously entered
16		order approved the procurement of renewable energy resources,
17		the portion of that order approving the procurement shall be
18		void, other than the procurement of renewable energy credits
19		from distributed renewable energy generation devices using
20		funds previously collected from electric utilities' retail
21		customers that take service under electric utilities' hourly
22		pricing tariff or tariffs and, for an electric utility that
23		serves less than 100,000 retail customers in the State, other
24		than the procurement of renewable energy credits for
25		distributed renewable energy generation devices.
26		(Source: P.A. 102-662, eff. 9-15-21.)

SB0025 Enrolled - 834 - LRB104 07069 BAB 17106 b
1		(220 ILCS 5/16-111.7)
2		Sec. 16-111.7. On-bill financing program; electric
3		utilities.
4		(a) The Illinois General Assembly finds that Illinois
5		homes and businesses have the potential to save energy through
6		conservation and cost-effective energy efficiency measures.
7		Programs created pursuant to this Section will allow utility
8		customers to purchase cost-effective energy efficiency
9		measures, including measures set forth in a
10		Commission-approved energy efficiency and demand-response plan
11		under Section 8-103 or 8-103B of this Act, with no required
12		initial upfront payment, and to pay the cost of those products
13		and services over time on their utility bill.
14		(b) Notwithstanding any other provision of this Act, an
15		electric utility serving more than 100,000 customers on
16		January 1, 2009 shall offer a Commission-approved on-bill
17		financing program ("program") that allows its eligible retail
18		customers, as that term is defined in Section 16-111.5 of this
19		Act, who own a residential single family home, duplex, or
20		other residential building with 4 or less units, or
21		condominium at which the electric service is being provided
22		(i) to borrow funds from a third party lender in order to
23		purchase electric energy efficiency measures approved under
24		the program for installation in such home or condominium
25		without any required upfront payment and (ii) to pay back such

SB0025 Enrolled - 835 - LRB104 07069 BAB 17106 b
1		funds over time through the electric utility's bill. Based
2		upon the process described in subsection (b-5) of this
3		Section, small commercial customers who own the premises at
4		which electric service is being provided may be included in
5		such program. After receiving a request from an electric
6		utility for approval of a proposed program and tariffs
7		pursuant to this Section, the Commission shall render its
8		decision within 120 days. If no decision is rendered within
9		120 days, then the request shall be deemed to be approved.
10		Beginning no later than December 31, 2013, an electric
11		utility subject to this subsection (b) shall also offer its
12		program to eligible retail customers that own multifamily
13		residential or mixed-use buildings with no more than 50
14		residential units, provided, however, that such customers must
15		either be a residential customer or small commercial customer
16		and may not use the program in such a way that repayment of the
17		cost of energy efficiency measures is made through tenants'
18		utility bills. An electric utility may impose a per site loan
19		limit not to exceed $150,000. The program, and loans issued
20		thereunder, shall only be offered to customers of the utility
21		that meet the requirements of this Section and that also have
22		an electric service account at the premises where the energy
23		efficiency measures being financed shall be installed.
24		Beginning no later than 2 years after the effective date of
25		this amendatory Act of the 99th General Assembly, the 50
26		residential unit limitation described in this paragraph shall

SB0025 Enrolled - 836 - LRB104 07069 BAB 17106 b
1		no longer apply, and the utility shall replace the per site
2		loan limit of $150,000 with a loan limit that correlates to a
3		maximum monthly payment that does not exceed 50% of the
4		customer's average utility bill over the prior 12-month
5		period.
6		Beginning no later than 2 years after the effective date
7		of this amendatory Act of the 99th General Assembly, an
8		electric utility subject to this subsection (b) shall also
9		offer its program to eligible retail customers that are Unit
10		Owners' Associations, as defined in subsection (o) of Section
11		2 of the Condominium Property Act, or Master Associations, as
12		defined in subsection (u) of the Condominium Property Act.
13		However, such customers must either be residential customers
14		or small commercial customers and may not use the program in
15		such a way that repayment of the cost of energy efficiency
16		measures is made through unit owners' utility bills. The
17		program and loans issued under the program shall only be
18		offered to customers of the utility that meet the requirements
19		of this Section and that also have an electric service account
20		at the premises where the energy efficiency measures being
21		financed shall be installed.
22		For purposes of this Section, "small commercial customer"
23		means, for an electric utility serving more than 3,000,000
24		retail customers, those customers having peak demand of less
25		than 100 kilowatts, and, for an electric utility serving less
26		than 3,000,000 retail customers, those customers having peak

SB0025 Enrolled - 837 - LRB104 07069 BAB 17106 b
1		demand of less than 150 kilowatts; provided, however, that in
2		the event the Commission, after the effective date of this
3		amendatory Act of the 98th General Assembly, approves changes
4		to a utility's tariffs that reflects new or revised demand
5		criteria for the utility's customer rate classifications, then
6		the utility may file a petition with the Commission to revise
7		the applicable definition of a small commercial customer to
8		reflect the new or revised demand criteria for the purposes of
9		this Section. After notice and hearing, the Commission shall
10		enter an order approving, or approving with modification, the
11		revised definition within 60 days after the utility files the
12		petition.
13		(b-5) Within 30 days after the effective date of this
14		amendatory Act of the 96th General Assembly, the Commission
15		shall convene a workshop process during which interested
16		participants may discuss issues related to the program,
17		including program design, eligible electric energy efficiency
18		measures, vendor qualifications, and a methodology for
19		ensuring ongoing compliance with such qualifications,
20		financing, sample documents such as request for proposals,
21		contracts and agreements, dispute resolution, pre-installment
22		and post-installment verification, and evaluation. The
23		workshop process shall be completed within 150 days after the
24		effective date of this amendatory Act of the 96th General
25		Assembly.
26		(c) Not later than 60 days following completion of the

SB0025 Enrolled - 838 - LRB104 07069 BAB 17106 b
1		workshop process described in subsection (b-5) of this
2		Section, each electric utility subject to subsection (b) of
3		this Section shall submit a proposed program to the Commission
4		that contains the following components:
5		(1) A list of recommended electric energy efficiency
6		measures that will be eligible for on-bill financing. An
7		eligible electric energy efficiency measure ("measure")
8		shall be a product or service for which one or more of the
9		following is true:
10		(A) (blank);
11		(B) the projected electricity savings (determined
12		by rates in effect at the time of purchase) are
13		sufficient to cover the costs of implementing the
14		measures, including finance charges and any program
15		fees not recovered pursuant to subsection (f) of this
16		Section; or
17		(C) the product or service is included in a
18		Commission-approved energy efficiency and
19		demand-response plan under Section 8-103 or 8-103B of
20		this Act.
21		(1.5) Beginning no later than 2 years after the
22		effective date of this amendatory Act of the 99th General
23		Assembly, an eligible electric energy efficiency measure
24		(measure) shall be a product or service that qualifies
25		under subparagraph (B) or (C) of paragraph (1) of this
26		subsection (c) or for which one or more of the following is

SB0025 Enrolled - 839 - LRB104 07069 BAB 17106 b
1		true:
2		(A) a building energy assessment, performed by an
3		energy auditor who is certified by the Building
4		Performance Institute or who holds a similar
5		certification, has recommended the product or service
6		as likely to be cost effective over the course of its
7		installed life for the building in which the measure
8		is to be installed; or
9		(B) the product or service is necessary to safely
10		or correctly install to code or industry standard an
11		efficiency measure, including, but not limited to,
12		installation work; changes needed to plumbing or
13		electrical connections; upgrades to wiring or
14		fixtures; removal of hazardous materials; correction
15		of leaks; changes to thermostats, controls, or similar
16		devices; and changes to venting or exhaust
17		necessitated by the measure. However, the costs of the
18		product or service described in this subparagraph (B)
19		shall not exceed 25% of the total cost of installing
20		the measure.
21		(2) The electric utility shall issue a request for
22		proposals ("RFP") to lenders for purposes of providing
23		financing to participants to pay for approved measures.
24		The RFP criteria shall include, but not be limited to, the
25		interest rate, origination fees, and credit terms. The
26		utility shall select the winning bidders based on its

SB0025 Enrolled - 840 - LRB104 07069 BAB 17106 b
1		evaluation of these criteria, with a preference for those
2		bids containing the rates, fees, and terms most favorable
3		to participants;
4		(3) The utility shall work with the lenders selected
5		pursuant to the RFP process, and with vendors, to
6		establish the terms and processes pursuant to which a
7		participant can purchase eligible electric energy
8		efficiency measures using the financing obtained from the
9		lender. The vendor shall explain and offer the approved
10		financing packaging to those customers identified in
11		subsection (b) of this Section and shall assist customers
12		in applying for financing. As part of the process, vendors
13		shall also provide to participants information about any
14		other incentives that may be available for the measures.
15		(4) The lender shall conduct credit checks or
16		undertake other appropriate measures to limit credit risk,
17		and shall review and approve or deny financing
18		applications submitted by customers identified in
19		subsection (b) of this Section. Following the lender's
20		approval of financing and the participant's purchase of
21		the measure or measures, the lender shall forward payment
22		information to the electric utility, and the utility shall
23		add as a separate line item on the participant's utility
24		bill a charge showing the amount due under the program
25		each month.
26		(5) A loan issued to a participant pursuant to the

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

SB0025 Enrolled - 842 - LRB104 07069 BAB 17106 b
1		(7) The total outstanding amount financed under the
2		program in this subsection and subsection (c-5) of this
3		Section shall not exceed $2.5 million for an electric
4		utility or electric utilities under a single holding
5		company, provided that the electric utility or electric
6		utilities may petition the Commission for an increase in
7		such amount. Beginning after the effective date of this
8		amendatory Act of the 99th General Assembly, the total
9		maximum outstanding amount financed under the program in
10		this subsection and subsections (c-5) and (c-10) of this
11		Section shall increase by $5,000,000 per year until such
12		time as the total maximum outstanding amount financed
13		reaches $20,000,000. For purposes of this Section,
14		"maximum outstanding amount financed" means the sum of all
15		principal that has been loaned and not yet repaid.
16		(c-5) Within 120 days after the effective date of this
17		amendatory Act of the 98th General Assembly, each electric
18		utility subject to the requirements of this Section shall
19		submit an informational filing to the Commission that
20		describes its plan for implementing the provisions of this
21		amendatory Act of the 98th General Assembly on or before
22		December 31, 2013. Such filing shall also describe how the
23		electric utility shall coordinate its program with any gas
24		utility or utilities that provide gas service to buildings
25		within the electric utility's service territory so that it is
26		practical and feasible for the owner of a multifamily building

SB0025 Enrolled - 843 - LRB104 07069 BAB 17106 b
1		to make a single application to access loans for both gas and
2		electric energy efficiency measures in any individual
3		building.
4		(c-10) No later than 365 days after the effective date of
5		this amendatory Act of the 99th General Assembly, each
6		electric utility subject to the requirements of this Section
7		shall submit an informational filing to the Commission that
8		describes its plan for implementing the provisions of this
9		amendatory Act of the 99th General Assembly that were
10		incorporated into this Section. Such filing shall also include
11		the criteria to be used by the program for determining if
12		measures to be financed are eligible electric energy
13		efficiency measures, as defined by paragraph (1.5) of
14		subsection (c) of this Section.
15		(d) A program approved by the Commission shall also
16		include the following criteria and guidelines for such
17		program:
18		(1) guidelines for financing of measures installed
19		under a program, including, but not limited to, RFP
20		criteria and limits on both individual loan amounts and
21		the duration of the loans;
22		(2) criteria and standards for identifying and
23		approving measures;
24		(3) qualifications of vendors that will market or
25		install measures, as well as a methodology for ensuring
26		ongoing compliance with such qualifications;

SB0025 Enrolled - 844 - LRB104 07069 BAB 17106 b
1		(4) sample contracts and agreements necessary to
2		implement the measures and program; and
3		(5) the types of data and information that utilities
4		and vendors participating in the program shall collect for
5		purposes of preparing the reports required under
6		subsection (g) of this Section.
7		(e) The proposed program submitted by each electric
8		utility shall be consistent with the provisions of this
9		Section that define operational, financial and billing
10		arrangements between and among program participants, vendors,
11		lenders, and the electric utility.
12		(f) An electric utility shall recover all of the prudently
13		incurred costs of offering a program approved by the
14		Commission pursuant to this Section, including, but not
15		limited to, all start-up and administrative costs and the
16		costs for program evaluation. All prudently incurred costs
17		under this Section shall be recovered from the residential and
18		small commercial retail customer classes eligible to
19		participate in the program through the automatic adjustment
20		clause tariff established pursuant to Section 8-103 or 8-103B
21		of this Act.
22		(g) An independent evaluation of a program shall be
23		conducted after 3 years of the program's operation. The
24		electric utility shall retain an independent evaluator who
25		shall evaluate the effects of the measures installed under the
26		program and the overall operation of the program, including,

SB0025 Enrolled - 845 - LRB104 07069 BAB 17106 b
1		but not limited to, customer eligibility criteria and whether
2		the payment obligation for permanent electric energy
3		efficiency measures that will continue to provide benefits of
4		energy savings should attach to the meter location. As part of
5		the evaluation process, the evaluator shall also solicit
6		feedback from participants and interested stakeholders. The
7		evaluator shall issue a report to the Commission on its
8		findings no later than 4 years after the date on which the
9		program commenced, and the Commission shall issue a report to
10		the Governor and General Assembly including a summary of the
11		information described in this Section as well as its
12		recommendations as to whether the program should be
13		discontinued, continued with modification or modifications or
14		continued without modification, provided that any recommended
15		modifications shall only apply prospectively and to measures
16		not yet installed or financed.
17		(h) An electric utility offering a Commission-approved
18		program pursuant to this Section shall not be required to
19		comply with any other statute, order, rule, or regulation of
20		this State that may relate to the offering of such program,
21		provided that nothing in this Section is intended to limit the
22		electric utility's obligation to comply with this Act and the
23		Commission's orders, rules, and regulations, including Part
24		280 of Title 83 of the Illinois Administrative Code.
25		(i) The source of a utility customer's electric supply
26		shall not disqualify a customer from participation in the

SB0025 Enrolled - 846 - LRB104 07069 BAB 17106 b
1		utility's on-bill financing program. Customers of alternative
2		retail electric suppliers may participate in the program under
3		the same terms and conditions applicable to the utility's
4		supply customers.
5		(j) This Section is repealed on January 1, 2027.
6		(Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17.)
7		(220 ILCS 5/16-115A)
8		Sec. 16-115A. Obligations of alternative retail electric
9		suppliers.
10		(a) An alternative retail electric supplier:
11		(i) shall comply with the requirements imposed on
12		public utilities by Sections 8-201 through 8-207, 8-301,
13		8-505 and 8-507 of this Act, to the extent that these
14		Sections have application to the services being offered by
15		the alternative retail electric supplier;
16		(ii) shall continue to comply with the requirements
17		for certification stated in subsection (d) of Section
18		16-115;
19		(iii) by May 31, 2020 and every June 30 thereafter,
20		shall submit to the Commission and the Office of the
21		Attorney General the rates the retail electric supplier
22		charged to residential customers in the prior year,
23		including each distinct rate charged and whether the rate
24		was a fixed or variable rate, the basis for the variable
25		rate, and any fees charged in addition to the supply rate,

SB0025 Enrolled - 847 - LRB104 07069 BAB 17106 b
1		including monthly fees, flat fees, or other service
2		charges; and
3		(iv) shall make publicly available on its website,
4		without the need for a customer login, rate information
5		for all of its variable, time-of-use, and fixed rate
6		contracts currently available to residential customers,
7		including, but not limited to, fixed monthly charges,
8		early termination fees, and kilowatt-hour charges; .
9		(v) shall provide to the Commission, in the form and
10		manner requested, the information necessary for the
11		Commission to compile and submit the integrated resource
12		plan required under Section 16-201; and
13		(vi) shall comply with the Commission's determinations
14		made pursuant to subsection (b-10) of Section 16-111.5.
15		(b) An alternative retail electric supplier shall obtain
16		verifiable authorization from a customer, in a form or manner
17		approved by the Commission consistent with Section 2EE of the
18		Consumer Fraud and Deceptive Business Practices Act, before
19		the customer is switched from another supplier.
20		(c) No alternative retail electric supplier, or electric
21		utility other than the electric utility in whose service area
22		a customer is located, shall (i) enter into or employ any
23		arrangements which have the effect of preventing a retail
24		customer with a maximum electrical demand of less than one
25		megawatt from having access to the services of the electric
26		utility in whose service area the customer is located or (ii)

SB0025 Enrolled - 848 - LRB104 07069 BAB 17106 b
1		charge retail customers for such access. This subsection shall
2		not be construed to prevent an arms-length agreement between a
3		supplier and a retail customer that sets a term of service,
4		notice period for terminating service and provisions governing
5		early termination through a tariff or contract as allowed by
6		Section 16-119.
7		(d) An alternative retail electric supplier that is
8		certified to serve residential or small commercial retail
9		customers shall not:
10		(1) deny service to a customer or group of customers
11		nor establish any differences as to prices, terms,
12		conditions, services, products, facilities, or in any
13		other respect, whereby such denial or differences are
14		based upon race, gender or income, except as provided in
15		Section 16-115E.
16		(2) deny service to a customer or group of customers
17		based on locality nor establish any unreasonable
18		difference as to prices, terms, conditions, services,
19		products, or facilities as between localities.
20		(3) warrant that it has a residential customer or
21		small commercial retail customer's express consent
22		agreement to access interval data as described in
23		subsection (b) of Section 16-122, unless the alternative
24		retail electric supplier has:
25		(A) disclosed to the consumer at the outset of the
26		offer that the alternative retail electric supplier

SB0025 Enrolled - 849 - LRB104 07069 BAB 17106 b
1		will access the consumer's interval data from the
2		consumer's utility with the consumer's express
3		agreement and the consumer's option to refuse to
4		provide express agreement to access the consumer's
5		interval data; and
6		(B) obtained the consumer's express agreement for
7		the alternative retail electric supplier to access the
8		consumer's interval data from the consumer's utility
9		in a separate letter of agency, a distinct response to
10		a third-party verification, or as a separate
11		affirmative consent during a recorded enrollment
12		initiated by the consumer. The disclosure by the
13		alternative retail electric supplier to the consumer
14		in this Section shall be conducted in, translated
15		into, and provided in a language in which the consumer
16		subject to the disclosure is able to understand and
17		communicate.
18		(4) release, sell, license, or otherwise disclose any
19		customer interval data obtained under Section 16-122 to
20		any third person except as provided for in Section 16-122
21		and paragraphs (1) through (4) of subsection (d-5) of
22		Section 2EE of the Consumer Fraud and Deceptive Business
23		Practices Act.
24		(e) An alternative retail electric supplier shall comply
25		with the following requirements with respect to the marketing,
26		offering and provision of products or services to residential

SB0025 Enrolled - 850 - LRB104 07069 BAB 17106 b
1		and small commercial retail customers:
2		(i) All marketing materials, including, but not
3		limited to, electronic marketing materials, in-person
4		solicitations, and telephone solicitations, shall contain
5		information that adequately discloses the prices, terms,
6		and conditions of the products or services that the
7		alternative retail electric supplier is offering or
8		selling to the customer and shall disclose the current
9		utility electric supply price to compare applicable at the
10		time the alternative retail electric supplier is offering
11		or selling the products or services to the customer and
12		shall disclose the date on which the utility electric
13		supply price to compare became effective and the date on
14		which it will expire. The utility electric supply price to
15		compare shall be the sum of the electric supply charge and
16		the transmission services charge and shall not include the
17		purchased electricity adjustment. The disclosure shall
18		include a statement that the price to compare does not
19		include the purchased electricity adjustment, and, if
20		applicable, the range of the purchased electricity
21		adjustment. All marketing materials, including, but not
22		limited to, electronic marketing materials, in-person
23		solicitations, and telephone solicitations, shall include
24		the following statement:
25		"(Name of the alternative retail electric
26		supplier) is not the same entity as your electric

SB0025 Enrolled - 851 - LRB104 07069 BAB 17106 b
1		delivery company. You are not required to enroll with
2		(name of alternative retail electric supplier).
3		Beginning on (effective date), the electric supply
4		price to compare is (price in cents per kilowatt
5		hour). The electric utility electric supply price will
6		expire on (expiration date). The utility electric
7		supply price to compare does not include the purchased
8		electricity adjustment factor. For more information go
9		to the Illinois Commerce Commission's free website at
10		www.pluginillinois.org.
11		If applicable, the statement shall also include the
12		following statement:
13		"The purchased electricity adjustment factor may
14		range between +.5 cents and -.5 cents per kilowatt
15		hour.".
16		This paragraph (i) does not apply to goodwill or
17		institutional advertising.
18		(ii) Before any customer is switched from another
19		supplier, the alternative retail electric supplier shall
20		give the customer written information that adequately
21		discloses, in plain language, the prices, terms and
22		conditions of the products and services being offered and
23		sold to the customer. This written information shall be
24		provided in a language in which the customer subject to
25		the marketing or solicitation is able to understand and
26		communicate, and the alternative retail electric supplier

SB0025 Enrolled - 852 - LRB104 07069 BAB 17106 b
1		shall not switch a customer who is unable to understand
2		and communicate in a language in which the marketing or
3		solicitation was conducted. The alternative retail
4		electric supplier shall comply with Section 2N of the
5		Consumer Fraud and Deceptive Business Practices Act.
6		(iii) An alternative retail electric supplier shall
7		provide documentation to the Commission and to customers
8		that substantiates any claims made by the alternative
9		retail electric supplier regarding the technologies and
10		fuel types used to generate the electricity offered or
11		sold to customers.
12		(iv) The alternative retail electric supplier shall
13		provide to the customer (1) itemized billing statements
14		that describe the products and services provided to the
15		customer and their prices, and (2) an additional
16		statement, at least annually, that adequately discloses
17		the average monthly prices, and the terms and conditions,
18		of the products and services sold to the customer.
19		(v) All in-person and telephone solicitations shall be
20		conducted in, translated into, and provided in a language
21		in which the consumer subject to the marketing or
22		solicitation is able to understand and communicate. An
23		alternative retail electric supplier shall terminate a
24		solicitation if the consumer subject to the marketing or
25		communication is unable to understand and communicate in
26		the language in which the marketing or solicitation is

SB0025 Enrolled - 853 - LRB104 07069 BAB 17106 b
1		being conducted. An alternative retail electric supplier
2		shall comply with Section 2N of the Consumer Fraud and
3		Deceptive Business Practices Act.
4		(vi) Each alternative retail electric supplier shall
5		conduct training for individual representatives engaged in
6		in-person solicitation and telemarketing to residential
7		customers on behalf of that alternative retail electric
8		supplier prior to conducting any such solicitations on the
9		alternative retail electric supplier's behalf. Each
10		alternative retail electric supplier shall submit a copy
11		of its training material to the Commission on an annual
12		basis and the Commission shall have the right to review
13		and require updates to the material. After initial
14		training, each alternative retail electric supplier shall
15		be required to conduct refresher training for its
16		individual representatives every 6 months.
17		(f) An alternative retail electric supplier may limit the
18		overall size or availability of a service offering by
19		specifying one or more of the following: a maximum number of
20		customers, maximum amount of electric load to be served, time
21		period during which the offering will be available, or other
22		comparable limitation, but not including the geographic
23		locations of customers within the area which the alternative
24		retail electric supplier is certificated to serve. The
25		alternative retail electric supplier shall file the terms and
26		conditions of such service offering including the applicable

SB0025 Enrolled - 854 - LRB104 07069 BAB 17106 b
1		limitations with the Commission prior to making the service
2		offering available to customers.
3		(g) Nothing in this Section shall be construed as
4		preventing an alternative retail electric supplier, which is
5		an affiliate of, or which contracts with, (i) an industry or
6		trade organization or association, (ii) a membership
7		organization or association that exists for a purpose other
8		than the purchase of electricity, or (iii) another
9		organization that meets criteria established in a rule adopted
10		by the Commission, from offering through the organization or
11		association services at prices, terms and conditions that are
12		available solely to the members of the organization or
13		association.
14		(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
15		(220 ILCS 5/16-119A)
16		Sec. 16-119A. Functional separation.
17		(a) Within 90 days after the effective date of this
18		amendatory Act of 1997, the Commission shall open a rulemaking
19		proceeding to establish standards of conduct for every
20		electric utility described in subsection (b). To create
21		efficient competition between suppliers of generating services
22		and sellers of such services at retail and wholesale, the
23		rules shall allow all customers of a public utility that
24		distributes electric power and energy to purchase electric
25		power and energy from the supplier of their choice in

SB0025 Enrolled - 855 - LRB104 07069 BAB 17106 b
1		accordance with the provisions of Section 16-104. In addition,
2		the rules shall address relations between providers of any 2
3		services described in subsection (b) to prevent undue
4		discrimination and promote efficient competition. Provided,
5		however, that a proposed rule shall not be published prior to
6		May 15, 1999.
7		(b) The Commission shall also have the authority to
8		investigate the need for, and adopt rules requiring,
9		functional separation between the generation services and the
10		delivery services of those electric utilities whose principal
11		service area is in Illinois as necessary to meet the objective
12		of creating efficient competition between suppliers of
13		generating services and sellers of such services at retail and
14		wholesale. After January 1, 2003, the Commission shall also
15		have the authority to investigate the need for, and adopt
16		rules requiring, functional separation between an electric
17		utility's competitive and non-competitive services.
18		(b-5) If there is a change in ownership of a majority of
19		the voting capital stock of an electric utility or the
20		ownership or control of any entity that owns or controls a
21		majority of the voting capital stock of an electric utility,
22		the electric utility shall have the right to file with the
23		Commission a new plan. The newly filed plan shall supersede
24		any plan previously approved by the Commission pursuant to
25		this Section for that electric utility, subject to Commission
26		approval. This subsection only applies to the extent that the

SB0025 Enrolled - 856 - LRB104 07069 BAB 17106 b
1		Commission rules for the functional separation of delivery
2		services and generation services provide an electric utility
3		with the ability to select from 2 or more options to comply
4		with this Section. The electric utility may file its revised
5		plan with the Commission up to one calendar year after the
6		conclusion of the sale, purchase, or any other transfer of
7		ownership described in this subsection. In all other respects,
8		an electric utility must comply with the Commission rules in
9		effect under this Section. The Commission may promulgate rules
10		to implement this subsection. This subsection shall have no
11		legal effect after January 1, 2005.
12		(c) In establishing or considering the need for rules
13		under subsections (a) and (b), the Commission shall take into
14		account the effects on the cost and reliability of service and
15		the obligation of the utility to provide bundled service under
16		this Act. The Commission shall adopt rules that are a cost
17		effective means to ensure compliance with this Section.
18		(d) Nothing in this Section shall be construed as imposing
19		any requirements or obligations that are in conflict with
20		federal law.
21		(e) Notwithstanding anything to the contrary, an electric
22		utility may market and promote the services, rates and
23		programs authorized by Sections 16-107, 16-107.8, and 16-108.6
24		of this Act.
25		(Source: P.A. 99-906, eff. 6-1-17.)

SB0025 Enrolled - 857 - LRB104 07069 BAB 17106 b
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) Illinois' bifurcated, existing RTO membership
10		structure has created significant concerns related to
11		delays in transmission build out, excessively long
12		interconnection queue processes, favoring polluting
13		generation resources over more cost-effective clean
14		sources, inhibiting State policies, and inexplicably
15		frustrating State efforts to address its resource adequacy
16		needs through the development of new generation.
17		(3) The governance structures of PJM Interconnection,
18		LLC (PJM) and the Midcontinent Independent System
19		Operator, Inc. (MISO) have consistently failed to
20		represent Illinois' interests.
21		(4) The Illinois Commerce Commission and the Illinois
22		Power Agency have the expertise to evaluate and present
23		findings related to the costs and benefits of Illinois
24		pursuing any one of the following 3 options: (1)
25		establishing a single, State-specific Independent System
26		Operator (ISO); (2) consolidating Illinois' existing

SB0025 Enrolled - 858 - LRB104 07069 BAB 17106 b
1		bifurcated RTO membership structure into one existing RTO;
2		or (3) maintaining the existing bifurcated RTO structure.
3		(b) The Commission and the Illinois Power Agency shall
4		conduct a joint study and publish the findings of the study to
5		evaluate whether (1) establishing a single State-operated ISO;
6		(2) consolidating this State's bifurcated RTO membership into
7		an existing RTO; or (3) maintaining the existing bifurcated
8		RTO structure, would be consistent with the State's goals and
9		would maximize benefits to State businesses and residents. As
10		a part of this evaluation, the Commission and the Illinois
11		Power Agency shall analyze whether it would be feasible and
12		practical for this State to pursue any of the options
13		described in this subsection (b).
14		(c) The Commission and the Illinois Power Agency shall
15		examine the costs and benefits, over a 20-year period, of this
16		State pursuing any of the options described in subsection (b).
17		The study shall examine the costs and benefits of such
18		participation over 20 years. The study shall examine the costs
19		and benefits to State ratepayers, including, but not limited
20		to, consideration of the regulatory, reliability, operational,
21		and competitive benefits of this State participating in one
22		existing RTO, as compared to participating in a State-specific
23		ISO, or continuing to participate in the current bifurcated
24		RTO structure. The costs and benefits evaluated should include
25		resource adequacy benefits, resilience, affordability, equity,
26		the impact on the environment, and the general health, safety,

SB0025 Enrolled - 859 - LRB104 07069 BAB 17106 b
1		and welfare of the People of this State.
2		The study shall, at a minimum, include the following, and
3		it may consider or suggest additional or alternative items:
4		(1) the appropriate timetable to (i) establish and
5		effectively transition to a State-specific ISO, or (ii)
6		consolidate into an existing RTO, taking into account how
7		that schedule could support the emission reduction
8		timeline established in Section 9.15 of the Environmental
9		Protection Act; and
10		(2) the appropriate benefits and costs to consider,
11		such as the regulatory, reliability, operational, and
12		competitive benefits, including, but not limited to:
13		(i) capacity market benefits and costs of
14		separating from the PJM and MISO territories versus
15		those of the status quo;
16		(ii) transmission benefits and costs of separating
17		from the PJM and MISO territories versus those of a
18		State-specific ISO;
19		(iii) the legal, correct, and appropriate exit
20		fees for leaving regional transmission organizations;
21		(iv) managing the State's energy resources to
22		supply electricity throughout the State versus the
23		existing bifurcated structure;
24		(v) the potential improvements in interconnection
25		queue speed versus the current lengthy delays in the
26		PJM and MISO processes;

SB0025 Enrolled - 860 - LRB104 07069 BAB 17106 b
1		(vi) the potential for a State-specific ISO to
2		more effectively value and enable resources, such as
3		storage of renewable resources, demand response,
4		energy efficiency, and the adoption of new
5		technologies and applications, versus the current PJM
6		and MISO structures; and
7		(vii) an evaluation of any improved ability for
8		the State to meet its goals and objectives in a new
9		State-specific ISO versus the existing structure.
10		After the completion of the study, if the Commission
11		and the Illinois Power Agency find that the results of the
12		study were overall beneficial to the citizens of this
13		State, then the Commission and the Illinois Power Agency
14		may conduct and publish an additional ISO policy study
15		that explores the steps required to establish a
16		State-specific ISO. The Governor and members of the
17		General Assembly may request an additional ISO policy
18		study, or any other follow-up study, regardless of the
19		outcome of the original study. An additional study may,
20		for example, investigate the steps required for this State
21		to consolidate into one existing RTO.
22		The additional ISO policy study shall investigate a
23		governance structure and design that would enable State
24		policy independence and more fully support State resource
25		adequacy and reliability while also complying with FERC
26		Order 2000. The additional ISO study may investigate how a

SB0025 Enrolled - 861 - LRB104 07069 BAB 17106 b
1		State-specific ISO would be able to demonstrate the
2		following issues, including, but not limited to:
3		(i) independence from market participants;
4		(ii) an appropriate scope and regional configuration;
5		(iii) possession of operational authority for all
6		transmission facilities under the control of the
7		State-specific ISO;
8		(iv) exclusive authority to maintain short-term
9		reliability of the grid;
10		(v) tariff administration and design;
11		(vi) congestion management;
12		(vii) management of parallel path flows;
13		(viii) provision of last resort for ancillary
14		services;
15		(ix) development of an Open Access Same-time
16		Information System (OASIS);
17		(x) market monitoring; and
18		(xi) responsibility for planning and expanding
19		facilities under its control.
20		(d) The Commission and the Illinois Power Agency shall
21		retain the services of technical and policy experts with
22		relevant fields of expertise. Given the critical and rapid
23		actions required under this Section, the Commission and the
24		Illinois Power Agency may procure the services of any
25		facilitator, expert, or consultant to assist with the
26		implementation of this Section. Such procurement is exempt

SB0025 Enrolled - 862 - LRB104 07069 BAB 17106 b
1		from the requirements of the Illinois Procurement Code under
2		Section 20-10 of the Illinois Procurement Code. The Commission
3		and the Illinois Power Agency may jointly determine that the
4		cost of any contract pursuant to this Section may be borne
5		initially by the relevant electric public utilities, but shall
6		be recovered as an expense through normal ratemaking
7		procedures. The Illinois Finance Authority, the Illinois
8		Environmental Protection Agency, and the Department of
9		Commerce and Economic Opportunity shall provide support to and
10		consult with the Commission and the Illinois Power Agency when
11		requested. The Commission and the Illinois Power Agency may
12		consult with other State agencies, commissions, or task forces
13		as needed.
14		(e) The Commission and the Illinois Power Agency may
15		solicit information, including confidential or proprietary
16		information, from entities likely to be impacted by the
17		creation of a State-specific ISO. The Commission and the
18		Illinois Power Agency may consult with and seek assistance
19		from (i) Independent System Operators in other states, such as
20		Texas, California, and New York, (ii) federal agencies, such
21		as the Federal Energy Regulatory Commission, and (iii) the
22		regional transmission organizations PJM and MISO. Any
23		information designated as confidential or proprietary
24		information by the entity providing the information shall be
25		kept confidential by the Commission, its consultants, and its
26		contractors, and the Illinois Power Agency, its consultants,

SB0025 Enrolled - 863 - LRB104 07069 BAB 17106 b
1		and its contractors, and is not subject to disclosure under
2		the Freedom of Information Act. The Office of the Attorney
3		General shall have access to, and maintain the confidentiality
4		of, such information pursuant to Section 6.5 of the Attorney
5		General Act.
6		(f) The Commission and the Illinois Power Agency shall
7		publish the joint final policy study no later than December 1,
8		2026 and suitable copies shall be delivered to the Governor
9		and members of the General Assembly.
10		(220 ILCS 5/16-145 new)
11		Sec. 16-145. Powering Up Illinois.
12		(a) For the purposes of this Section:
13		"Electric utility" means an electric utility serving more
14		than 500,000 customers in this State.
15		"Energization" and "energize" means the connection of new
16		electric vehicle charging infrastructure projects over 5
17		megawatts to the electrical grid or upgrading electrical
18		capacity to provide adequate service to such electric vehicle
19		charging infrastructure projects. "Energization" and
20		"energize" do not include activities related to connecting
21		electricity supply resources.
22		"Energization time period" means the period of time that
23		begins when the electric utility receives a substantially
24		complete energization project application and ends when the
25		electric service associated with the project is installed and

SB0025 Enrolled - 864 - LRB104 07069 BAB 17106 b
1		energized, consistent with the service obligations set forth
2		in the Section 8-101 of the Public Utilities Act.
3		(b) The Commission shall adopt rules to establish and
4		track reasonable average and maximum target energization time
5		periods for energization projects. Such rules shall, at a
6		minimum, establish the following:
7		(1) reasonable average and maximum target energization
8		time periods. The targets shall ensure that work is
9		completed in a safe and reliable manner that minimizes
10		delay in meeting the date requested by a customer for
11		completion of the energization project to the greatest
12		extent possible. The targets may vary based on factors,
13		including, but not limited to, customer class, size of the
14		project, the complexity and magnitude of the work
15		required, and uncertainties regarding the readiness of the
16		customer project needing energization. The targets may
17		also recognize any factors beyond the electric utility's
18		control;
19		(2) requirements for an electric utility to report to
20		the Commission, at least annually, in order to track and
21		improve electric utility performance. The report shall, at
22		a minimum, include the average, median, and standard
23		deviation time between receiving an application for
24		electrical service and energizing the electrical service,
25		and detailed explanations for energization time periods
26		that exceed the target maximum for energization projects,

SB0025 Enrolled - 865 - LRB104 07069 BAB 17106 b
1		constraints and obstacles to each type of energization,
2		including, but not limited to, funding limitations,
3		qualified staffing availability, or equipment
4		availability, and any other information that the
5		Commission, in its discretion, concludes that such reports
6		should contain; and
7		(3) procedures for customers to report energization
8		delays to the Commission.
9		(c) If an electric utility's average time period for
10		energization in a calendar year exceeds the Commission's
11		target averages or if an electric utility has exceeded the
12		Commission's target maximums as established by rule, the
13		electric utility shall include in its report pursuant to rules
14		adopted under paragraph (2) of subsection (b) a detailed
15		remedial plan for meeting the targets in the future. The
16		Commission may require modification to the electric utility's
17		remedial plan to ensure that the electric utility meets
18		targets promptly.
19		(d) Data reported by electric utilities shall be
20		anonymized or aggregated to the extent necessary to prevent
21		identifying individual customers. The Commission shall make
22		all such reports publicly available.
23		(e) In addition to requiring remedial plans pursuant to
24		subsection (c) of this Section, the Commission may require an
25		electric utility to take any remedial actions necessary to
26		achieve the Commission's targets.

SB0025 Enrolled - 866 - LRB104 07069 BAB 17106 b
1		(220 ILCS 5/16-201 new)
2		Sec. 16-201. Integrated resource plan development.
3		(a) The General Assembly hereby finds that:
4		(1) In 2021, Illinois set itself on the path to a clean
5		energy future that would produce the least amount of
6		carbon and copollutant emissions while ensuring adequate,
7		reliable, affordable, efficient, and environmentally
8		sustainable electric service at the lowest total cost over
9		time and in a manner that benefits the Illinois economy
10		and workforce and improves the quality of life, including
11		environmental health, for all its citizens.
12		(2) In the ensuing years, Illinois has created a
13		strong economic environment that has led to the
14		revitalization and expansion of its manufacturing sector
15		and has made Illinois an attractive place for the
16		technology industry to locate new data and quantum
17		computing centers. These developments have led to the
18		creation of good-paying jobs for working families.
19		(3) The unforeseen growth in the manufacturing and
20		technology sectors will likely lead to a dramatic increase
21		in electricity demand over time.
22		(4) The long interconnection times and the capacity
23		market structures enacted by the 2 regional transmission
24		organizations that Illinois is split between further
25		exacerbate the potential for an imbalance between

SB0025 Enrolled - 867 - LRB104 07069 BAB 17106 b
1		electricity supply and demand.
2		(5) The new sources of load growth from the
3		manufacturing and technology sectors combined with
4		external challenges require a more nimble and responsive
5		administrative approach to effectively address future
6		resource adequacy challenges.
7		(6) The Illinois agencies that oversee and implement
8		Illinois energy policy must have the ability to (i) fully
9		understand current and future resource adequacy needs,
10		(ii) plan for what resources could be utilized to address
11		such needs, (iii) be able to coordinate, modify, expand,
12		and direct all of Illinois' existing energy programs and
13		policies so as to address any resource adequacy or
14		reliability concerns, and (iv) direct the development of
15		new energy programs and policies in order meet resource
16		adequacy and reliability needs without the need for
17		additional legislative action.
18		(b) The purpose of this Section is to ensure that the
19		Commission, the agencies, electric utilities supplying
20		electric service in Illinois, stakeholders, market
21		participants, and policymakers have a common set of data and
22		information regarding the State's electricity resource needs
23		in order to plan for sufficient electricity resources to serve
24		Illinois customers in a manner that is adequate, safe,
25		reliable, affordable, efficient, environmentally sustainable,
26		at the lowest cost over time, and consistent with the energy

SB0025 Enrolled - 868 - LRB104 07069 BAB 17106 b
1		policy goals of the State, including, but not limited to, the
2		clean energy policy established by Public Act 102-662. To that
3		end, this Section establishes a requirement that the agencies
4		prepare an integrated resource plan and submit such plan to
5		the Commission consistent with this Section for the
6		Commission's review and approval after an opportunity for
7		notice and hearing.
8		(c) Unless otherwise specified, as used in this Section,
9		the following terms shall have the following meanings:
10		(1) "Advanced transmission technologies" means
11		technologies, tools, and software that improve power flows
12		over transmission systems and lines. "Advanced
13		transmission technologies" includes, but is not limited
14		to, the following:
15		(i) technology that dynamically adjusts the rated
16		capacity of transmission lines based on real-time
17		conditions;
18		(ii) advanced power flow controls used to actively
19		control the flow of electricity across transmission
20		lines to optimize usage or relieve congestion;
21		(iii) software or hardware used to identify
22		optimal transmission grid configurations or enable
23		routing power flows around congestion points; and
24		(iv) advanced transmission line conductors that
25		have a direct current electrical resistance at least
26		10% lower than existing conductors of a similar

SB0025 Enrolled - 869 - LRB104 07069 BAB 17106 b
1		diameter on the transmission system.
2		(2) "Agencies" means the Illinois Commerce Commission
3		Staff, the Illinois Power Agency, the Illinois Finance
4		Authority, the Illinois Environmental Protection Agency,
5		and any consultants those agencies retain, including, but
6		not limited to, the consultant retained by the Commission
7		pursuant to subsection (j) of this Section and the
8		consultant retained by the Illinois Power Agency pursuant
9		to paragraph (1) of subsection (a) of Section 1-75 of the
10		Illinois Power Agency Act.
11		(3) "Clean energy" means energy generation that
12		either:
13		(A) emits no on-site SO2, NOx, mercury, or any
14		other regulated pollutants; or
15		(B) as shown through pollution control
16		technologies, has reduced a generator's CO2 emissions
17		by 90% compared to what the generator would have
18		otherwise emitted and that has CO2 emissions less than
19		130 lb/MWh.
20		(4) "Regional transmission organization" or "RTO"
21		means PJM Interconnection, LLC (PJM) and the Midcontinent
22		Independent System Operator, Inc. (MISO) or the regional
23		transmission organization or independent system operator
24		of which the electric utility is a member or would be a
25		member, given the location of the electric utility's
26		customers, if it were required to be a member.

SB0025 Enrolled - 870 - LRB104 07069 BAB 17106 b
1		(d) The agencies, coordinated by Commission staff, shall
2		compile and propose an integrated resource plan in compliance
3		with this Section. The agencies may consult with each electric
4		utility that has more than 500,000 electric retail customers
5		in developing the plan and the plan shall consider any
6		necessary interactions between RTO zones in the State.
7		Commission staff shall submit the initial integrated resource
8		plan to the Commission no later than November 15, 2026, the
9		second integrated resource plan to the Commission no later
10		than September 30, 2029, and each subsequent plan to the
11		Commission every 4 years thereafter no later than September 30
12		of the applicable year. For the first integrated resource plan
13		due on November 15, 2026, the agencies shall take into account
14		the resource adequacy report prepared pursuant to subsection
15		(o) of Section 9.15 of the Environmental Protection Act and
16		shall specifically address any and all divergences from the
17		analysis and conclusions in the report. At any time after the
18		submission of a plan, the agencies may submit an update to the
19		plan if the agencies believe that a material change in the
20		inputs or conclusions of the plan is warranted. The agencies
21		shall notify the Commission as soon as practicable of the
22		material change and the potential update to the plan. The
23		Commission shall publish the integrated resource plan on its
24		website.
25		(e) An alternative retail electric supplier shall provide
26		information related to the resource needs of its customers

SB0025 Enrolled - 871 - LRB104 07069 BAB 17106 b
1		located in an electric utility's service territory as
2		requested by the agencies or the Commission to compile and
3		develop the plan required by this Section.
4		(f) Commission staff shall lead the agencies in the
5		development of the integrated resource plan to ensure that a
6		plan submitted pursuant to this Section includes a detailed
7		analysis of the following:
8		(1) an evaluation of the future electric resource
9		needs in each electric utility's service area for periods
10		of at least 5, 10, 15, and 20 years such that the plan
11		coincides with the timelines established in Section 9.15
12		of Title II of the Environmental Protection Act and is
13		designed to support those standards to the maximum extent
14		practicable on the schedule established therein;
15		(2) peak demand and energy usage forecasts, such that
16		the plan:
17		(i) contains no fewer than 3 scenarios of (i)
18		forecasted peak demand, (ii) net peak demand if
19		different from peak demand, (iii) non-coincidental
20		peak demand, and (iv) energy usage, to capture a
21		reasonable range of forecasts based on historic trends
22		and a diverse range of more conservative to high load
23		growth based on reasonable projections. The scenarios
24		should consider estimates of peak demand corresponding
25		to seasons or other applicable time periods as defined
26		by the regional transmission organization in which

SB0025 Enrolled - 872 - LRB104 07069 BAB 17106 b
1		this State's electric utilities are a member;
2		(ii) reflects known changes in facility and
3		appliance codes and standards;
4		(iii) reflects load reductions from
5		State-sponsored programs;
6		(iv) reflects load reductions from programs
7		sponsored by electric utilities;
8		(v) reflects load reductions from aggregators of
9		retail customers that can be applied to the host
10		load-serving entity's resource adequacy requirement;
11		(vi) reflects load reductions from any other
12		sources including out-of-state programs that could
13		influence load;
14		(vii) reflects expected adoption of other
15		distributed energy resources, including
16		behind-the-meter generation; and
17		(viii) includes any additional sensitivities as
18		determined by the agencies;
19		(3) an analysis of all generation and energy resource
20		options available to meet the range of load forecasts with
21		a focus on the first period of at least 5 years covered by
22		the plan, including an analysis of existing supply found
23		within each electric utility's service area and new supply
24		expected to come online across that period of at least 5
25		years, such that the plan shall consider the following:
26		(i) the current and projected status of electric

SB0025 Enrolled - 873 - LRB104 07069 BAB 17106 b
1		resource adequacy throughout the State from sources
2		the agencies deem reasonable;
3		(ii) a range of resource options that can be
4		deployed at a reasonable scale, that provide clean
5		energy to the maximum extent practicable, and that
6		include generation and energy resources on both the
7		demand-side and supply-side;
8		(iii) developing technologies that will be
9		commercially viable during the period of analysis;
10		(iv) reflect reasonable assumptions for capital
11		and operating costs and the performance of resource
12		technologies. The calculation of resource costs shall
13		include reasonable expected costs for transmission
14		interconnection and network upgrades made necessary by
15		the addition of each resource; and
16		(v) appropriate considerations for implementation,
17		such as:
18		(A) timelines for implementation, including,
19		but not limited to, siting, permitting,
20		engineering, transmission interconnection, and the
21		time it takes to modify existing programs or
22		create new programs and put them into operation;
23		(B) recommendations for how new clean
24		resources should be developed to respond to
25		resource adequacy challenges; and
26		(C) any other requirements for implementation;

SB0025 Enrolled - 874 - LRB104 07069 BAB 17106 b
1		(4) confirmation that the resource adequacy and
2		reliability requirements employed in the plan meet the
3		following conditions:
4		(i) the plan must reflect planning reserve margin
5		requirements established by the corresponding RTO,
6		other resource adequacy requirements set by an
7		applicable authority as authorized by the State, or
8		another standard chosen by the Commission; and
9		(ii) the integrated resource plan may reflect a
10		supplemental reliability analysis, including the
11		evaluation of reliability metrics not prescribed by an
12		RTO or other applicable authority as authorized by the
13		State;
14		(5) consistency with existing State and federal
15		environmental laws and policies, including, but not
16		limited to, the decarbonization goals set forth in Section
17		9.15 of the Illinois Environmental Protection Act. The
18		plan may consider potential changes in State and federal
19		environmental laws and policies. The plan must provide
20		expected emissions for CO2, SO2, NOx, mercury, and any
21		other regulated pollutants in order to analyze the impact
22		of retirement timelines on emissions reductions. The plan
23		must be consistent with the State's other clean energy
24		goals and targets, including, but not limited to, its
25		renewable portfolio standard, its energy efficiency
26		portfolio standard, the carbon mitigation credit program,

SB0025 Enrolled - 875 - LRB104 07069 BAB 17106 b
1		and its energy storage system portfolio standard. The plan
2		shall include an analysis of the following:
3		(i) the State's current progress toward its
4		renewable energy resource development goals, its
5		storage development goals, and its energy efficiency
6		and demand-response goals, as well as the pace of the
7		development of renewables, energy storage, including
8		distributed storage, the deployment of virtual power
9		plants, and demand-response utilization; and
10		(ii) the status of the State's CO2e and copollutant
11		emissions reductions and its current status and
12		progress toward developing emerging clean energy
13		technologies;
14		(6) consideration of the following additional issues:
15		(i) an integrated resource plan shall be designed
16		to collectively meet all of Illinois' energy policy
17		goals and shall describe:
18		(A) how the plan complies with the various
19		requirements of State energy policy;
20		(B) the assumptions and analytical methods
21		used in the plan;
22		(C) recommendations for how State policy
23		should serve to facilitate the development of new
24		resources;
25		(D) the impacts of the plan on customer costs,
26		including net present value costs relative to

SB0025 Enrolled - 876 - LRB104 07069 BAB 17106 b
1		alternatives; and
2		(E) how the plan improves energy equity within
3		environmental justice and equity investment
4		eligible communities, as defined by the Energy
5		Transition Act, including, but not limited to,
6		reducing energy burden, ensuring affordability of
7		electric utility bills and uninterruptible
8		essential utility service, and reducing barriers
9		to accessing renewable energy;
10		(ii) an integrated resource plan shall include a
11		discussion of the steps needed to implement the plan,
12		including, but not limited to, options and steps to
13		bring on new or increased energy generated from any
14		recommended resources for the 5 years after the plan
15		would be implemented, that align with State clean
16		energy policy;
17		(iii) an integrated resource plan shall consider
18		the information and conclusions set forth in the
19		renewable energy access plan developed in accordance
20		with Section 8-512, including, but not limited to,
21		information concerning the locations of renewable
22		energy access plan zones, considerations of advanced
23		transmission technologies to increase efficiencies,
24		and different transmission planning options and cost
25		allocations;
26		(iv) an integrated resource plan may consider the

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1		impacts of future or anticipated changes in State and
2		federal energy laws and policies; and
3		(v) any solutions for any additional conclusions;
4		(7) if the agencies choose, portfolio-optimization
5		results based on the following:
6		(i) capacity expansion and production cost
7		modeling consistent with the conditions and
8		constraints set forth in this Section;
9		(ii) optimized candidate portfolios that align
10		with the load-growth scenarios described in paragraph
11		(2) of subsection (f) of this Section and any
12		additional portfolios chosen by the agencies to
13		reflect alternative policy or technology assumptions;
14		(iii) a comparison of total system cost on a
15		net-present-value basis, customer rate and bill
16		impacts, risk metrics, including, but not limited to,
17		cost variability under fuel-price and load shocks,
18		emissions trajectories, and key reliability
19		indicators; and
20		(iv) an identification of a preferred portfolio or
21		portfolios that best satisfy the objectives of
22		affordability, reliability, equity, and emission
23		reduction and a narrative explanation of why the
24		portfolio is recommended; and
25		The agencies may request that PJM and MISO, or their
26		respective successor organizations, conduct a resource

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1		adequacy and reliability study. The study shall include the
2		megawatt amount of energy storage capacity that would maintain
3		resource adequacy during the study period to fully meet the
4		requirements for CO2e and copollutant emissions reductions
5		under Public Act 102-662 that would not otherwise be met by the
6		interconnection queue and without large transmission upgrades,
7		including maintaining sufficient in-State capacity to meet the
8		zonal requirements of MISO Zone 4 or the PJM ComEd Zone. The
9		study shall also identify recommended geographic locations for
10		new storage and clean energy to mitigate local reliability
11		risks, including at or near the sites of any generator
12		deactivations to maximize the efficient utilization of
13		existing infrastructure.
14		(220 ILCS 5/16-202 new)
15		Sec. 16-202. Integrated resource plan review and approval.
16		(a) The Commission shall enter its order approving or
17		approving with modifications an integrated resource plan
18		within 180 days after the agencies filing the plan and any
19		companion reports or other information. The Commission may
20		extend the period of review of the plan for no more than an
21		additional 180 days.
22		(b) The Commission may approve a plan or a modified plan
23		and authorize its implementation only if, after notice and
24		hearing, including the conduct of discovery and taking of
25		evidence, it finds that the plan:

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1		(1) addresses any resource adequacy challenges in the
2		5 years immediately following approval of the plan, while
3		also taking into account the 10 years following the plan;
4		(2) prepares the State to best address issues of
5		resource adequacy at the least amount of CO2e and
6		copollutant emissions;
7		(3) considers the emissions' impacts on environmental
8		justice communities while taking into account all
9		applicable labor and equity standards;
10		(4) supports the provisioning of adequate, reliable,
11		affordable, efficient, and environmentally sustainable
12		electric service at the lowest total cost over time; and
13		(5) utilizes the expansion of renewable energy, energy
14		storage, virtual power plants and distributed energy
15		storage, energy efficiency, demand response, time-of-use
16		rates or other mechanisms designed to manage peak load,
17		transmission development, carbon mitigation credits or any
18		other clean energy strategies to the maximum extent
19		practicable to resolve any identified resource adequacy
20		shortfall or reliability violation in a cost-effective,
21		affordable, timely, and clean manner.
22		(c) The Commission may, as a part of its decision to
23		approve a plan or modified plan and to the extent consistent
24		with the uniform allocation of costs required under subsection
25		(k) of Section 16-108, order changes to existing programs,
26		direct specific actions within existing programs including the

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1		authorization to support the expansion of an existing program,
2		including, but not limited to:
3		(1) any of the following plans or programs designed to
4		increase the amount of generation and capacity available:
5		(i) the Long-Term Renewable Resources Procurement
6		Plan, including programs and procurements authorized
7		through that Plan, and to increase the limitations
8		placed on the procurement of renewable energy
9		resources established pursuant to subparagraph (E) of
10		paragraph (1) of subsection (c) of Section 1-75 of the
11		Illinois Power Agency Act in order to increase,
12		direct, or adjust procurements of renewable energy
13		resources to support new renewable energy projects;
14		(ii) the Energy Storage Resources Procurement
15		Plan, including programs and procurements authorized
16		through that Plan, and to increase the procurement of
17		energy storage established pursuant to subsection
18		(d-20) of Section 1-75 of the Illinois Power Agency
19		Act in order to increase or adjust procurements for
20		new energy storage;
21		(iii) the carbon mitigation credit procurement
22		plans established pursuant to subsection (d-10) of
23		Section 1-75 of the Illinois Power Agency Act in order
24		to preserve existing carbon-free energy resources,
25		including extending or expanding carbon mitigation
26		credit contract awards in accordance with a new

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1		schedule of baseline costs;
2		(iv) the Illinois Power Agency's annual
3		electricity procurement plans established pursuant to
4		paragraph (2) of subsection (d) of Section 16-111.5,
5		including modification of the products to be procured
6		and allowing for costs associated with the purchase of
7		new or additional products to be socialized across all
8		retail customers or all load-serving entities, as
9		applicable; and
10		(v) any additional programs designed to procure
11		appropriate sources of new clean energy and capacity
12		resources, including any associated clean attribute
13		credits; and
14		(2) any of the following designed to manage energy
15		demand, including, but not limited to:
16		(i) extending or expanding the energy efficiency
17		programs implemented by electric utilities and the
18		limitation on the amount of energy efficiency and
19		demand-response measures implemented pursuant to
20		Section 8-103B in order to gain increased load
21		reductions; and
22		(ii) the Multi-Year Integrated Grid Plans
23		implemented by electric utilities pursuant to Section
24		16-105.17 in order to extend or expand programs
25		related to peak load management and reduction,
26		including, but not limited to, virtual power plants,

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1		front of the meter distributed storage, demand
2		response, and time-of-use rates.
3		(d) If all of the changes made to the programs pursuant to
4		this Section would reasonably be insufficient to balance
5		supply and demand and avoid a resource adequacy shortfall,
6		then the Commission may delay, in whole or in part, the CO2e
7		and copollutant emissions reductions requirements found in
8		Section 9.15 of the Environmental Protection Act but only to
9		the minimum extent and duration necessary to address the
10		resource adequacy shortfall needs of the State. If the
11		Commission finds that reducing or delaying the emissions
12		reductions requirements is necessary, despite any or all of
13		the changes made pursuant to this Section, then it shall also
14		include in its final order recommendations to the General
15		Assembly on what additional policies may be adopted that could
16		avoid future modifications to the emissions reductions.
17		(e) Unless otherwise specified by the Commission, the
18		order approving the plan or modified plan shall become
19		effective January 1 of the calendar year immediately following
20		the issuance of the order. The agencies, electric utilities,
21		and any other impacted entities shall comply with any of the
22		Commission's orders, and when required seek approval from the
23		Commission and make any required modifications to their plans,
24		programs, or related initiatives in a manner consistent with
25		the process and timing for those changes as outlined in the
26		approved plans or, if none is specified, as soon as

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1		practicable. If the integrated resource plan approved by the
2		Commission contains recommendations that are outside the
3		Commission's authority, the Commission shall communicate any
4		such recommendations to the Governor and the General Assembly.
5		(f) Given the critical and rapid actions required under
6		this Section, the Commission may procure the services of any
7		facilitator, expert, or consultant, including the procurement
8		monitor retained by the Commission pursuant to paragraph (2)
9		of subsection (c) of Section 16-111.5. Such procurement is
10		exempt from the requirements of the Illinois Procurement Code,
11		pursuant to Section 20-10 of that Code.
12		(g) Costs that are prudently and reasonably incurred by
13		electric utilities to comply with the requirements of this
14		Section shall be recovered and shall be excluded from the
15		calculation performed under paragraph (6) of subsection (f) of
16		Section 16-108.18. Nothing in the Commission's order directing
17		changes to a prior approved plan as enumerated in this Section
18		shall be the sole basis for a finding of imprudence or
19		unreasonableness or the lack of use or usefulness of any
20		investment or expenditure.
21		(h) If the Commission's final order under this Section
22		includes the approval of rate increases through the expansion
23		of existing programs, the creation of new programs, or the
24		increase of limitations placed on procurements as described
25		under paragraphs (1) and (2) of subsection (c), the Commission
26		shall submit notice to the General Assembly of the increases

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1		included in the final order, including the estimated monthly
2		cost impact on customers and the expected costs savings or
3		benefits of such actions. After receipt of a notice, any
4		member of the General Assembly may introduce in the General
5		Assembly a joint resolution stating that the General Assembly
6		desires to suspend the rate increases, or suspend a portion of
7		the rate increases, identified in the final order and
8		specifying the rationale for the General Assembly's
9		determination.
10		(1) If the General Assembly passes a joint resolution
11		under this subsection (h) that takes effect prior to the
12		effective date of the Commission's final order, the
13		General Assembly shall send notice to the Commission of
14		the resolution, and the Commission shall suspend its final
15		order. Within 30 days of receipt of the General Assembly's
16		notice, the Commission shall reopen the docket approving
17		the plan or modified plan in order to take into account the
18		General Assembly's reduction or elimination of the rate
19		increases. The Commission shall approve the modified plan
20		within 120 days of reopening the docket, including the
21		conduct of discovery and the taking of evidence, and send
22		notice to the General Assembly of its modified plan. The
23		General Assembly may rescind its desire to suspend the
24		rate increases, or suspend a portion of the rate
25		increases, by adoption of a subsequent joint resolution by
26		each chamber of the General Assembly within 30 days of

SB0025 Enrolled - 885 - LRB104 07069 BAB 17106 b
1		receipt of the Commission's notice that would put into
2		effect the Commission's original final order.
3		(2) If the General Assembly fails to pass a joint
4		resolution under this subsection (h) prior to the
5		effective date of the Commission's final order, the
6		associated rate increases shall go into effect pursuant to
7		the schedule specified in the Commission's final order
8		approving the plan or modified plan.
9		(i) The Commission may adopt rules to implement the
10		requirements of this Section.
11		(220 ILCS 5/17-900)
12		Sec. 17-900. Customer self-generation of electricity.
13		(a) The General Assembly finds and declares that municipal
14		systems and electric cooperatives shall continue to be
15		governed by their respective governing bodies, but that such
16		governing bodies should recognize and implement policies to
17		provide the opportunity for their residential and small
18		commercial customers who wish to self-generate electricity and
19		for reasonable credits to customers for excess electricity,
20		balanced against the rights of the other non-self-generating
21		customers. This includes creating consistent, fair policies
22		that are accessible to all customers and transparent, fair
23		processes for raising and addressing any concerns.
24		(b) Customers have the right to install renewable
25		generating facilities to be located on the customer's premises

SB0025 Enrolled - 886 - LRB104 07069 BAB 17106 b
1		or customer's side of the billing meter and that are intended
2		primarily to offset the customer's own electrical requirements
3		and produce, consume, and store their own renewable energy
4		without discriminatory repercussions from an electric
5		cooperative or municipal system. This includes a customer's
6		rights to:
7		(1) generate, consume, and deliver excess renewable
8		energy to the distribution grid and reduce his or her use
9		of electricity obtained from the grid;
10		(2) use technology to store energy at his or her
11		residence;
12		(3) interconnect his or her electrical system that
13		generates renewable energy, stores energy, or any
14		combination thereof, with the electricity meter on the
15		customer's premises that is provided by an electric
16		cooperative or municipal system:
17		(A) in a timely manner;
18		(B) in accordance with requirements established by
19		the electric cooperative or municipal utility to
20		ensure the safety of utility workers; and
21		(C) after providing written notice to the electric
22		cooperative or municipal utility system providing
23		service in the service territory, installing a
24		nomenclature plate on the electrical meter panel and
25		meeting all applicable State and local safety and
26		electrical code requirements associated with

SB0025 Enrolled - 887 - LRB104 07069 BAB 17106 b
1		installing a parallel distributed generation system;
2		and
3		(4) receive fair credit for excess energy delivered to
4		the distribution grid; and
5		(5) for residential and small commercial customers,
6		interconnect renewable energy systems sized up to and
7		including 25 kW AC.
8		(c) The policies of municipal systems and electric
9		cooperatives regarding self-generation and credits for excess
10		electricity may reasonably differ from those required of other
11		entities by Article XVI of the Public Utilities Act or other
12		Acts. The credits must recognize the value of self-generation
13		to the distribution grid and benefits to other customers.
14		(c-5) The policies of municipal systems and electric
15		cooperatives regarding self-generation and credits for excess
16		electricity shall not require customers to name the municipal
17		system or electric cooperative as an additional insured on the
18		customer's insurance policies or have any minimum liability
19		limit requirement in connection with the installation and
20		operation of renewable generating facilities if the renewable
21		generating facilities meet the safety standards listed in the
22		applicable interconnection agreement and the contractor used
23		to install the renewable generating facilities is licensed and
24		possesses commercial general liability insurance coverage of
25		at least $1,000,000 per occurrence and $2,000,000 in the
26		aggregate per year.

SB0025 Enrolled - 888 - LRB104 07069 BAB 17106 b
1		(d) Within 180 days after this amendatory Act of the 102nd
2		General Assembly, each electric cooperative and municipal
3		system shall update its policies for the interconnection and
4		fair crediting of customer self-generation and storage if
5		necessary, to comply with the standards of subsection (b) of
6		this Section. Each electric cooperative and municipal system
7		shall post its updated policies to a public-facing area of its
8		website.
9		(e) An electric cooperative or municipal system customer
10		who produces, consumes, and stores his or her own renewable
11		energy shall not face discriminatory rate design, fees or
12		charges, treatment, or excessive compliance requirements that
13		would unreasonably affect that customer's right to
14		self-generate electricity as provided for in this Section.
15		(f) An electric cooperative or municipal utility system
16		customer shall have a right to appeal any decision related to
17		self-generation and storage that violates these rights to
18		self-generation and non-discrimination pursuant to the
19		provisions of this Section through a complaint under the
20		Administrative Review Law or similar legal process.
21		(Source: P.A. 102-662, eff. 9-15-21.)
22		(220 ILCS 5/20-140 new)
23		Sec. 20-140. Interconnection Working Group.
24		(a) The Commission shall establish an Interconnection
25		Working Group. The Working Group shall include representatives

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1		from electric utilities, developers of renewable electric
2		generating facilities, representatives of new large loads
3		seeking grid interconnection, other industries that regularly
4		apply for interconnection with the electric utilities as
5		appropriate, representatives of distributed generation
6		customers, the Commission staff, and other stakeholders with a
7		substantial interest in the topics addressed by the
8		Interconnection Working Group.
9		(b) The Interconnection Working Group shall address at
10		least the following issues in relation to new generation and
11		new large loads:
12		(1) the cost of and the best available technology for
13		interconnection and metering, including the
14		standardization and publication of standard costs;
15		(2) transparency, accuracy, and use of the
16		distribution interconnection queue and hosting capacity
17		maps;
18		(3) distribution system upgrade cost avoidance through
19		use of advanced inverter functions, energy storage, and
20		load management;
21		(4) predictability of the queue management process and
22		enforcement of timelines;
23		(5) benefits and challenges associated with group
24		studies and cost sharing;
25		(6) minimum requirements for application to the
26		interconnection process and throughout the interconnection

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1		process to avoid queue clogging behavior;
2		(7) the process and customer service for
3		interconnecting customers adopting distributed energy
4		resources, including energy storage;
5		(8) options for metering distributed energy resources,
6		including energy storage;
7		(9) interconnection of new technologies, including
8		smart inverters and energy storage;
9		(10) collection, examination, and sharing of data on
10		Level 1 interconnection costs, including cost and type of
11		upgrades required for interconnection, and the use of this
12		data to inform the final standardized cost of Level 1
13		interconnection;
14		(11) determination of a single standardized cost for
15		Level 1 interconnections, which shall not exceed $200; and
16		(12) such other technical, policy, and tariff issues
17		related to and affecting interconnection performance and
18		customer service as determined by the Interconnection
19		Working Group.
20		(c) The Commission may create subcommittees of the
21		Interconnection Working Group to focus on specific issues of
22		importance, as appropriate.
23		(d) The Interconnection Working Group shall report to the
24		Commission on recommended improvements to interconnection
25		rules, tariffs, and policies as determined by the
26		Interconnection Working Group at least every year. A report

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1		shall include consensus recommendations of the Interconnection
2		Working Group and, if applicable, additional recommendations
3		for which consensus was not reached. Non-consensus shall not
4		be a basis for excluding recommendations that are majority or
5		minority recommendations. The Commission shall use the report
6		from the Interconnection Working Group to determine whether
7		processes should be commenced to formally codify or implement
8		the recommendations. The Interconnection Working Group shall
9		provide the reports under this subsection (d) to the
10		Commission on at least the following topics in the order
11		listed below within a reasonable time, but no later than 12
12		months, after the effective date of this amendatory Act of the
13		104th General Assembly: (A) a mechanism for good cause
14		extensions to construction timelines as long as the
15		interconnection customer reasonably demonstrates progress; (B)
16		a mechanism for all electric utilities to accept cash, letters
17		of credit, or bonds for any deposits required under the
18		interconnection agreement; (C) cost sharing for distribution
19		system upgrades and interconnection facilities for multiple
20		interconnection customers attempting to interconnect on the
21		same feeder or substation; (D) requirements that
22		interconnection studies process without delay based on queue
23		position or status of applications ahead in the queue, and
24		associated requirements for disclosure of contingent upgrades;
25		(E) provisions allowing for queue reservation for the
26		interconnection of projects installed on public school land to

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1		accommodate timing constraints of school board approval and
2		budgeting; and (F) if feasible within the time allotted for
3		the initial report, parameters for utility interconnection
4		studies of energy storage systems not paired with distributed
5		generation that are based on the proposed operational profile
6		of the energy storage systems.
7		(d-5) Within 12 months after the report directed by
8		subsection (d) has been submitted, the Working Group shall
9		report to the Commission on the following: (A) mandatory
10		disclosures on the hosting capacity map and studies for
11		contingent upgrades including timelines for notice of
12		responsibility and payment; (B) a framework for concurrent
13		study on multiple feeders for a distributed energy resource;
14		and (C) if not provided in the initial report required under
15		subsection (d), parameters for utility interconnection studies
16		of energy storage systems not paired with distributed
17		generation that are based on the proposed operational profile
18		of the energy storage systems.
19		(d-10) Within 12 months after the report directed by
20		subsection (d-5) has been submitted, the Working Group shall
21		report to the Commission on the following: (A) dynamic hosting
22		capacity maps; (B) standards for public queue and hosting
23		capacity map information regarding individual projects in
24		queue, including (i) distributed generation nameplate
25		capacity, (ii) paired or stand-alone energy storage system
26		nameplate capacity, (iii) detailed estimated upgrade costs,

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

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

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1		interconnection applicant may submit the interconnection
2		dispute to the Ombudsperson, or his or her designee. The
3		Ombudsperson, or his or her designee, shall provide a
4		recommended resolution of such dispute within 30 days after
5		the Ombudsperson determines that full information from all
6		parties to the dispute has been received. The electric
7		utility, the interconnection customer, the interconnection
8		applicant, or any other party authorized to initiate dispute
9		resolution under the Commission's rules authorized by this Act
10		may include the Ombudsperson's recommendation in any formal
11		complaint before the Commission.
12		(f) The Office is encouraged to include at least one
13		employee, at the Bureau Chief's discretion, with a background
14		in engineering of renewable resources and distribution
15		interconnections.
16		(220 ILCS 5/Art. XXIII heading new)
17		ARTICLE XXIII. SITING OF QUALIFIED ENERGY FACILITIES
18		(220 ILCS 5/23-105 new)
19		Sec. 23-105. Findings. The General Assembly finds that the
20		timely siting and development of commercial wind energy
21		facilities, commercial solar energy facilities and energy
22		storage system facilities is critical to the State's energy
23		security and that it is the policy of the State that:
24		(1) the General Assembly has adopted state-wide county

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1		siting regulations to establish uniform standards for
2		commercial wind energy facilities, commercial solar energy
3		facilities, and energy storage system facilities
4		throughout this State;
5		(2) a consistent dispute resolution process, with
6		respect to the siting and development of commercial wind
7		energy facilities, commercial solar energy facilities and
8		energy storage system facilities is necessary to provide
9		fair and expeditious decisions on siting disputes to
10		parties affected by the development and siting of a
11		renewable energy project;
12		(3) empowering the Commission to resolve siting
13		disputes and issue siting certificates would allow parties
14		to avoid time-consuming and costly litigation and would
15		provide consistency and certainty to the renewable energy
16		siting and development process in the State; and
17		(4) the Commission has the relevant expertise to
18		establish and govern a renewable energy siting certificate
19		issuance and dispute resolution process.
20		(220 ILCS 5/23-110 new)
21		Sec. 23-110. Definitions. In this Article:
22		"Applicable State siting law" means Section 5-12020 of the
23		Counties Code for commercial wind energy facilities and
24		commercial solar energy facilities and means Section 5-12024
25		of the Counties Code for energy storage system facilities

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1		"Commercial solar energy facility" has the meaning given
2		to that term in subsection (a) of Section 5-12020 of the
3		Counties Code. "Commercial solar energy facility" includes
4		supporting facilities, as defined in subsection (a) of Section
5		5-12020 of the Counties Code.
6		"Commercial wind energy facility" has the meaning given to
7		that term in subsection (a) of Section 5-12020 of the Counties
8		Code. "Commercial wind energy facility" includes supporting
9		facilities, as defined in subsection (a) of Section 5-12020 of
10		the Counties Code.
11		"Energy storage system facility" has the meaning given to
12		that term in Section 5-12024 of the Counties Code. "Energy
13		storage system facility" includes supporting facilities, as
14		defined in subsection (a) of Section 5-12024 of the Counties
15		Code.
16		"Facility owner" means the owner of or an applicant for a
17		qualified energy facility.
18		"Qualified energy facility" means any one or more of the
19		following that has a nameplate capacity of 50 megawatts or
20		greater and is located in an unincorporated area not within
21		the zoning jurisdiction of an incorporated municipality: a
22		commercial wind energy facility, a commercial solar energy
23		facility, or an energy storage system facility.
24		"Respondent" means the county, municipality, township,
25		road district, or other unit of local government whose action
26		or inaction is the subject of the dispute.

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1		(220 ILCS 5/23-115 new)
2		Sec. 23-115. Resolution of disputes between facility
3		owners and units of local government related to the siting of
4		qualified energy facilities.
5		(a) The expedited procedures in this Section shall be used
6		to enforce the provisions of the applicable State siting law.
7		(b) No petition may be filed under this Section until the
8		facility owner that intends to file the petition has first
9		notified the respondent of the alleged violation of the
10		applicable State siting law and offered the respondent 7 days
11		to correct or take substantial steps to begin and diligently
12		pursue curing the alleged violation. Provision of notice and
13		the opportunity to correct the situation creates a rebuttable
14		presumption of knowledge under this Section. After the filing
15		of a petition under this Section, the parties may agree to
16		follow the mediation process under Section 10-101.1 of this
17		Act. The time periods specified in subdivision (c)(7) of this
18		Section shall be tolled during the time spent in mediation
19		under Section 10-101.1.
20		(c) A facility owner may file a petition with the
21		Commission alleging a violation of the applicable State siting
22		law in accordance with this subsection. The following
23		procedures shall govern the dispute resolution process:
24		(1) The petition shall be filed with the Chief Clerk
25		of the Commission and shall be served in hand upon the

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1		respondent, the executive director, and the general
2		counsel of the Commission at the time of the filing.
3		(2) A petition filed under this subsection shall
4		include a statement that the requirements of subsection
5		(b) have been fulfilled and that the respondent did not
6		correct the situation as requested.
7		(3) Reasonable discovery specific to the issue of the
8		petition may commence upon filing of the petition.
9		(4) An answer and any other responsive pleading to the
10		petition shall be filed with the Commission and served at
11		the same time upon the complainant, the executive
12		director, and the general counsel of the Commission within
13		7 days after the date on which the petition is filed.
14		(5) If the answer or responsive pleading raises the
15		issue that the petition violates subsection (f) of this
16		Section, the complainant may file a reply to such
17		allegation within 3 days after actual service of such
18		answer or responsive pleading. Within 4 days after the
19		time for filing a reply has expired, the administrative
20		law judge shall either issue a written decision dismissing
21		the petition as frivolous in violation of subsection (f)
22		of this Section including the reasons for such disposition
23		or shall issue an order directing that the petition shall
24		proceed.
25		(6) A pre-hearing conference shall be held within 14
26		days after the date on which the petition is filed.

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1		(7) The hearing shall commence within 45 days of the
2		date on which the petition is filed and shall be conducted
3		by an administrative law judge. Parties and the Commission
4		staff shall be entitled to present evidence and legal
5		argument in oral or written form as deemed appropriate by
6		the administrative law judge. The administrative law judge
7		shall issue a proposed order within 90 days after the date
8		on which the petition is filed. The proposed order shall
9		include reasons for the disposition of the petition and,
10		if a violation of the applicable State siting law is
11		found, directions and a deadline for correction of the
12		violation.
13		(8) Any party may file a petition requesting the
14		Commission to review the proposed order of the
15		administrative law judge or arbitrator within 5 days after
16		the proposed order is issued and file exceptions to the
17		proposed order. Any party may file a response to a
18		petition for review within 3 business days after actual
19		service of the petition. After the time for filing of the
20		petition for review, but no later than 60 days after the
21		proposed order of the administrative law judge, the
22		Commission shall decide to adopt the proposed order of the
23		administrative law judge or shall issue its own final
24		order.
25		(d) In resolving disputes filed under this Section, the
26		administrative law judge and the Commission shall make

SB0025 Enrolled - 901 - LRB104 07069 BAB 17106 b
1		determinations based on the requirements and intent of the
2		applicable State siting law.
3		(e) In resolving disputes under this Section, the
4		Commission shall have authority to issue a siting certificate
5		for a qualified energy facility if the Commission determines
6		that:
7		(1) the respondent denied the qualified energy
8		facility a siting certificate; and
9		(2) the qualified energy facility is in compliance
10		with the applicable State siting laws for a qualified
11		energy facility.
12		For the purposes of this Section, a commercial wind energy
13		facility and commercial solar energy facility shall be in
14		compliance with Section 5-12020 of the Counties Code and an
15		energy storage system shall be in compliance with Section
16		5-12024 of the Counties Code. If the Commission determines
17		that there is substantial harm to the facility owner, the
18		Commission may, notwithstanding any other provision of this
19		Act, seek temporary, preliminary, or permanent injunctive
20		relief from a court of competent jurisdiction either before or
21		after the hearing.
22		(f) A party shall not bring or defend a proceeding brought
23		under this Section or assert or controvert an issue in a
24		proceeding brought under this Section, unless there is a
25		non-frivolous basis for doing so. By presenting a pleading,
26		written motion, or other paper in petition or defense of the

SB0025 Enrolled - 902 - LRB104 07069 BAB 17106 b
1		actions or inaction of a party under this Section, a party is
2		certifying to the Commission that to the best of that party's
3		knowledge, information, and belief, formed after a reasonable
4		inquiry of the subject matter of the petition or defense, that
5		the petition or defense is well grounded in law and fact, and
6		under the circumstances:
7		(1) it is not being presented to harass the other
8		party, cause unnecessary delay, or create needless
9		increases in the cost of litigation; and
10		(2) the allegations and other factual contentions have
11		evidentiary support or, if specifically so identified, are
12		likely to have evidentiary support after reasonable
13		opportunity for further investigation or discovery as
14		defined herein.
15		(g) If, after notice and a reasonable opportunity to
16		respond, the Commission determines that subsection (f) has
17		been violated, the Commission shall impose appropriate
18		sanctions upon the party or parties that have violated
19		subsection (i) or are responsible for the violation.
20		(h) An appeal of a Commission order made pursuant to this
21		Section shall not effectuate a stay of the order unless a court
22		of competent jurisdiction specifically finds that the party
23		seeking the stay will likely succeed on the merits, that the
24		party will suffer irreparable harm without the stay, and that
25		the stay is in the public interest.
26		(i) The Commission shall assess the parties under this

SB0025 Enrolled - 903 - LRB104 07069 BAB 17106 b
1		subsection for all of the Commission's costs of investigation
2		and conduct of the proceedings brought under this Section
3		including, but not limited to, the prorated salaries of staff,
4		attorneys, administrative law judges, and support personnel
5		and including any travel and per diem, directly attributable
6		to the petition brought pursuant to this Section, but
7		excluding those costs provided for in subsection (g), dividing
8		the costs according to the resolution of the petition brought
9		under this Section. All assessments made under this subsection
10		shall be paid into the Public Utility Fund within 60 days after
11		receiving notice of the assessments from the Commission.
12		Interest at the statutory rate shall accrue after the
13		expiration of the 60-day period. The Commission is authorized
14		to apply to a court of competent jurisdiction for an order
15		requiring payment.
16		(220 ILCS 5/23-120 new)
17		Sec. 23-120. Effect of siting certificate. A siting
18		approval certificate authorizes the facility owner receiving
19		the certificate to construct, maintain, and decommission the
20		qualified energy facility.
21		(220 ILCS 5/23-125 new)
22		Sec. 23-125. Rulemaking. The Commission may adopt rules to
23		implement the requirements of this Article.

SB0025 Enrolled - 904 - LRB104 07069 BAB 17106 b
1		Section 90-40. The Electric Transmission Systems
2		Construction Standards Act is amended by changing Sections 5
3		and 15 as follows:
4		(220 ILCS 32/5)
5		Sec. 5. Definitions. For the purposes of this Act:
6		"Commission" means the Illinois Commerce Commission.
7		"Construction contractor" means any nonutility entity
8		responsible for the construction, installation, maintenance,
9		or repair of electric transmission systems subject to this
10		Act.
11		"Electric transmission systems" means an electrical
12		transmission system designed and constructed with the
13		capability of being safely and reliably energized at 69
14		kilovolts or more, including transmission lines, transmission
15		towers, conductors, insulators, foundations, grounding
16		systems, access roads, and all associated transmission
17		facilities, including transmission substations. "Electric
18		transmission systems" does not include projects located on the
19		electric generating facility's side of the facility's point of
20		interconnection or facilities not functionally classified as
21		transmission systems, regardless of voltage.
22		"OSHA" means Occupational Safety and Health
23		Administration.
24		"Utility" means an entity that is a public utility, as
25		defined in Section 3-105 of the Public Utilities Act, and that

SB0025 Enrolled - 905 - LRB104 07069 BAB 17106 b
1		serves residential customers. has the meaning given to that
2		term in Section 3-105 of the Public Utilities Act.
3		(Source: P.A. 103-1066, eff. 2-20-25.)
4		(220 ILCS 32/15)
5		Sec. 15. Requirements for construction contractors.
6		(a) Prevailing wage compliance. All utilities and
7		construction contractors responsible for the construction,
8		installation, maintenance, or repair of electric transmission
9		systems shall pay employees performing the construction,
10		installation, maintenance, or repair work of such systems
11		wages and benefits consistent with the Prevailing Wage Act.
12		(b) Training and competence requirement. To ensure safety
13		and reliability in the construction, installation,
14		maintenance, and repair of electric transmission systems, each
15		electric utility and construction contractor must demonstrate
16		the competence of their employees who are performing the work
17		of construction, installation, maintenance, or repair of
18		electric transmission systems, which shall be consistent with
19		the standards required by Illinois utilities as of January 1,
20		2007, or greater. Competence must include, at a minimum: (1)
21		completion, or active participation with ultimate completion,
22		in an accredited or recognized apprenticeship program for the
23		relevant craft, trade, or skill; or (2) a minimum of 2 years of
24		direct employment in the specific work function.
25		The Commission shall oversee compliance to ensure

SB0025 Enrolled - 906 - LRB104 07069 BAB 17106 b
1		employees meet these standards.
2		(c) Safety training. All employees engaged in the
3		construction, installation, maintenance, or repair of electric
4		transmission systems must successfully complete OSHA-certified
5		safety training required for their specific roles on the
6		project site.
7		(d) Diversity Plan.
8		(1) All construction contractors engaged in the
9		construction, installation, maintenance, or repair of
10		electric transmission systems shall develop a Diversity
11		Plan that sets forth:
12		(A) the goals for apprenticeship hours to be
13		performed by minorities and women;
14		(B) the goals for total hours to be performed by
15		underrepresented minorities and women; and
16		(C) spending for women-owned, minority-owned,
17		veteran-owned, and small business enterprises in the
18		previous calendar year.
19		(2) These goals shall be expressed as a percentage of
20		the total work performed by the construction contractor
21		submitting the plan and the actual spending for all
22		women-owned, minority-owned, veteran-owned, and small
23		business enterprises shall also be expressed as a
24		percentage of the total work performed by the construction
25		contractor submitting the Diversity Plan.
26		(3) For purposes of the Diversity Plan, minorities and

SB0025 Enrolled - 907 - LRB104 07069 BAB 17106 b
1		women shall have the same definition as defined in the
2		Business Enterprise for Minorities, Women, and Persons
3		with Disabilities Act.
4		(4) The construction contractor shall submit the
5		Diversity Plan to the Commission.
6		(Source: P.A. 103-1066, eff. 2-20-25.)
7		Section 90-45. The Environmental Protection Act is amended
8		by changing Sections 9.15, 25, and 39 as follows:
9		(415 ILCS 5/9.15)
10		Sec. 9.15. Greenhouse gases.
11		(a) An air pollution construction permit shall not be
12		required due to emissions of greenhouse gases if the
13		equipment, site, or source is not subject to regulation, as
14		defined by 40 CFR 52.21, as now or hereafter amended, for
15		greenhouse gases or is otherwise not addressed in this Section
16		or by the Board in regulations for greenhouse gases. These
17		exemptions do not relieve an owner or operator from the
18		obligation to comply with other applicable rules or
19		regulations.
20		(b) An air pollution operating permit shall not be
21		required due to emissions of greenhouse gases if the
22		equipment, site, or source is not subject to regulation, as
23		defined by Section 39.5 of this Act, for greenhouse gases or is
24		otherwise not addressed in this Section or by the Board in

SB0025 Enrolled - 908 - LRB104 07069 BAB 17106 b
1		regulations for greenhouse gases. These exemptions do not
2		relieve an owner or operator from the obligation to comply
3		with other applicable rules or regulations.
4		(c) (Blank).
5		(d) (Blank).
6		(e) (Blank).
7		(f) As used in this Section:
8		"Carbon dioxide emission" means the plant annual CO2 total
9		output emission as measured by the United States Environmental
10		Protection Agency in its Emissions & Generation Resource
11		Integrated Database (eGrid), or its successor.
12		"Carbon dioxide equivalent emissions" or "CO2e" means the
13		sum total of the mass amount of emissions in tons per year,
14		calculated by multiplying the mass amount of each of the 6
15		greenhouse gases specified in Section 3.207, in tons per year,
16		by its associated global warming potential as set forth in 40
17		CFR 98, subpart A, table A-1 or its successor, and then adding
18		them all together.
19		"Cogeneration" or "combined heat and power" refers to any
20		system that, either simultaneously or sequentially, produces
21		electricity and useful thermal energy from a single fuel
22		source.
23		"Copollutants" refers to the 6 criteria pollutants that
24		have been identified by the United States Environmental
25		Protection Agency pursuant to the Clean Air Act.
26		"Electric generating unit" or "EGU" means a fossil

SB0025 Enrolled - 909 - LRB104 07069 BAB 17106 b
1		fuel-fired stationary boiler, combustion turbine, or combined
2		cycle system that serves a generator that has a nameplate
3		capacity greater than 25 MWe and produces electricity for
4		sale.
5		"Environmental justice community" means the definition of
6		that term based on existing methodologies and findings, used
7		and as may be updated by the Illinois Power Agency and its
8		program administrator in the Illinois Solar for All Program.
9		"Equity investment eligible community" or "eligible
10		community" means the geographic areas throughout Illinois that
11		would most benefit from equitable investments by the State
12		designed to combat discrimination and foster sustainable
13		economic growth. Specifically, eligible community means the
14		following areas:
15		(1) areas where residents have been historically
16		excluded from economic opportunities, including
17		opportunities in the energy sector, as defined as R3 areas
18		pursuant to Section 10-40 of the Cannabis Regulation and
19		Tax Act; and
20		(2) areas where residents have been historically
21		subject to disproportionate burdens of pollution,
22		including pollution from the energy sector, as established
23		by environmental justice communities as defined by the
24		Illinois Power Agency pursuant to the Illinois Power
25		Agency Act, excluding any racial or ethnic indicators.
26		"Equity investment eligible person" or "eligible person"

SB0025 Enrolled - 910 - LRB104 07069 BAB 17106 b
1		means the persons who would most benefit from equitable
2		investments by the State designed to combat discrimination and
3		foster sustainable economic growth. Specifically, eligible
4		person means the following people:
5		(1) persons whose primary residence is in an equity
6		investment eligible community;
7		(2) persons whose primary residence is in a
8		municipality, or a county with a population under 100,000,
9		where the closure of an electric generating unit or mine
10		has been publicly announced or the electric generating
11		unit or mine is in the process of closing or closed within
12		the last 5 years;
13		(3) persons who are graduates of or currently enrolled
14		in the foster care system; or
15		(4) persons who were formerly incarcerated.
16		"Existing emissions" means:
17		(1) for CO2e, the total average tons-per-year of CO2e
18		emitted by the EGU or large GHG-emitting unit either in
19		the years 2018 through 2020 or, if the unit was not yet in
20		operation by January 1, 2018, in the first 3 full years of
21		that unit's operation; and
22		(2) for any copollutant, the total average
23		tons-per-year of that copollutant emitted by the EGU or
24		large GHG-emitting unit either in the years 2018 through
25		2020 or, if the unit was not yet in operation by January 1,
26		2018, in the first 3 full years of that unit's operation.

SB0025 Enrolled - 911 - LRB104 07069 BAB 17106 b
1		"Green hydrogen" means a power plant technology in which
2		an EGU creates electric power exclusively from electrolytic
3		hydrogen, in a manner that produces zero carbon and
4		copollutant emissions, using hydrogen fuel that is
5		electrolyzed using a 100% renewable zero carbon emission
6		energy source.
7		"Large greenhouse gas-emitting unit" or "large
8		GHG-emitting unit" means a unit that is an electric generating
9		unit or other fossil fuel-fired unit that itself has a
10		nameplate capacity or serves a generator that has a nameplate
11		capacity greater than 25 MWe and that produces electricity,
12		including, but not limited to, coal-fired, coal-derived,
13		oil-fired, natural gas-fired, and cogeneration units.
14		"NOx emission rate" means the plant annual NOx total output
15		emission rate as measured by the United States Environmental
16		Protection Agency in its Emissions & Generation Resource
17		Integrated Database (eGrid), or its successor, in the most
18		recent year for which data is available.
19		"Public greenhouse gas-emitting units" or "public
20		GHG-emitting unit" means large greenhouse gas-emitting units,
21		including EGUs, that are wholly owned, directly or indirectly,
22		by one or more municipalities, municipal corporations, joint
23		municipal electric power agencies, electric cooperatives, or
24		other governmental or nonprofit entities, whether organized
25		and created under the laws of Illinois or another state.
26		"SO2 emission rate" means the "plant annual SO2 total

SB0025 Enrolled - 912 - LRB104 07069 BAB 17106 b
1		output emission rate" as measured by the United States
2		Environmental Protection Agency in its Emissions & Generation
3		Resource Integrated Database (eGrid), or its successor, in the
4		most recent year for which data is available.
5		(g) All EGUs and large greenhouse gas-emitting units that
6		use coal or oil as a fuel and are not public GHG-emitting units
7		shall permanently reduce all CO2e and copollutant emissions to
8		zero no later than January 1, 2030.
9		(h) All EGUs and large greenhouse gas-emitting units that
10		use coal as a fuel and are public GHG-emitting units shall
11		permanently reduce CO2e emissions to zero no later than
12		December 31, 2045. Any source or plant with such units must
13		also reduce their CO2e emissions by 45% from existing
14		emissions by no later than January 1, 2035. If the emissions
15		reduction requirement is not achieved by December 31, 2035,
16		the plant shall retire one or more units or otherwise reduce
17		its CO2e emissions by 45% from existing emissions by June 30,
18		2038.
19		(i) All EGUs and large greenhouse gas-emitting units that
20		use gas as a fuel and are not public GHG-emitting units shall
21		permanently reduce all CO2e and copollutant emissions to zero,
22		including through unit retirement or the use of 100% green
23		hydrogen or other similar technology that is commercially
24		proven to achieve zero carbon emissions, according to the
25		following:
26		(1) No later than January 1, 2030: all EGUs and large

SB0025 Enrolled - 913 - LRB104 07069 BAB 17106 b
1		greenhouse gas-emitting units that have a NOx emissions
2		rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
3		greater than 0.006 lb/MWh, and are located in or within 3
4		miles of an environmental justice community designated as
5		of January 1, 2021 or an equity investment eligible
6		community.
7		(2) No later than January 1, 2040: all EGUs and large
8		greenhouse gas-emitting units that have a NOx emission
9		rate of greater than 0.12 lbs/MWh or a SO2 emission rate
10		greater than 0.006 lb/MWh, and are not located in or
11		within 3 miles of an environmental justice community
12		designated as of January 1, 2021 or an equity investment
13		eligible community. After January 1, 2035, each such EGU
14		and large greenhouse gas-emitting unit shall reduce its
15		CO2e emissions by at least 50% from its existing emissions
16		for CO2e, and shall be limited in operation to, on average,
17		6 hours or less per day, measured over a calendar year, and
18		shall not run for more than 24 consecutive hours except in
19		emergency conditions, as designated by a Regional
20		Transmission Organization or Independent System Operator.
21		(3) No later than January 1, 2035: all EGUs and large
22		greenhouse gas-emitting units that began operation prior
23		to the effective date of this amendatory Act of the 102nd
24		General Assembly and have a NOx emission rate of less than
25		or equal to 0.12 lb/MWh and a SO2 emission rate less than
26		or equal to 0.006 lb/MWh, and are located in or within 3

SB0025 Enrolled - 914 - LRB104 07069 BAB 17106 b
1		miles of an environmental justice community designated as
2		of January 1, 2021 or an equity investment eligible
3		community. Each such EGU and large greenhouse gas-emitting
4		unit shall reduce its CO2e emissions by at least 50% from
5		its existing emissions for CO2e no later than January 1,
6		2030.
7		(4) No later than January 1, 2040: All remaining EGUs
8		and large greenhouse gas-emitting units that have a heat
9		rate greater than or equal to 7000 BTU/kWh. Each such EGU
10		and Large greenhouse gas-emitting unit shall reduce its
11		CO2e emissions by at least 50% from its existing emissions
12		for CO2e no later than January 1, 2035.
13		(5) No later than January 1, 2045: all remaining EGUs
14		and large greenhouse gas-emitting units.
15		(j) All EGUs and large greenhouse gas-emitting units that
16		use gas as a fuel and are public GHG-emitting units shall
17		permanently reduce all CO2e and copollutant emissions to zero,
18		including through unit retirement or the use of 100% green
19		hydrogen or other similar technology that is commercially
20		proven to achieve zero carbon emissions by January 1, 2045.
21		(k) All EGUs and large greenhouse gas-emitting units that
22		utilize combined heat and power or cogeneration technology
23		shall permanently reduce all CO2e and copollutant emissions to
24		zero, including through unit retirement or the use of 100%
25		green hydrogen or other similar technology that is
26		commercially proven to achieve zero carbon emissions by

SB0025 Enrolled - 915 - LRB104 07069 BAB 17106 b
1		January 1, 2045.
2		(k-5) No EGU or large greenhouse gas-emitting unit that
3		uses gas as a fuel and is not a public GHG-emitting unit may
4		emit, in any 12-month period, CO2e or copollutants in excess of
5		that unit's existing emissions for those pollutants.
6		(l) Notwithstanding subsections (g) through (k-5), large
7		GHG-emitting units including EGUs may temporarily continue
8		emitting CO2e and copollutants after any applicable deadline
9		specified in any of subsections (g) through (k-5) if it has
10		been determined, as described in paragraphs (1) and (2) of
11		this subsection, that ongoing operation of the EGU is
12		necessary to maintain power grid supply and reliability or
13		ongoing operation of large GHG-emitting unit that is not an
14		EGU is necessary to serve as an emergency backup to
15		operations. Up to and including the occurrence of an emission
16		reduction deadline under subsection (i), all EGUs and large
17		GHG-emitting units must comply with the following terms:
18		(1) if an EGU or large GHG-emitting unit that is a
19		participant in a regional transmission organization
20		intends to retire, it must submit documentation to the
21		appropriate regional transmission organization by the
22		appropriate deadline that meets all applicable regulatory
23		requirements necessary to obtain approval to permanently
24		cease operating the large GHG-emitting unit;
25		(2) if any EGU or large GHG-emitting unit that is a
26		participant in a regional transmission organization

SB0025 Enrolled - 916 - LRB104 07069 BAB 17106 b
1		receives notice that the regional transmission
2		organization has determined that continued operation of
3		the unit is required, the unit may continue operating
4		until the issue identified by the regional transmission
5		organization is resolved. The owner or operator of the
6		unit must cooperate with the regional transmission
7		organization in resolving the issue and must reduce its
8		emissions to zero, consistent with the requirements under
9		subsection (g), (h), (i), (j), (k), or (k-5), as
10		applicable, as soon as practicable when the issue
11		identified by the regional transmission organization is
12		resolved; and
13		(3) any large GHG-emitting unit that is not a
14		participant in a regional transmission organization shall
15		be allowed to continue emitting CO2e and copollutants
16		after the zero-emission date specified in subsection (g),
17		(h), (i), (j), (k), or (k-5), as applicable, in the
18		capacity of an emergency backup unit if approved by the
19		Illinois Commerce Commission.
20		(m) No variance, adjusted standard, or other regulatory
21		relief otherwise available in this Act may be granted to the
22		emissions reduction and elimination obligations in this
23		Section.
24		(n) By June 30 of each year, beginning in 2025, the Agency
25		shall prepare and publish on its website a report setting
26		forth the actual greenhouse gas emissions from individual

SB0025 Enrolled - 917 - LRB104 07069 BAB 17106 b
1		units and the aggregate statewide emissions from all units for
2		the prior year.
3		(o) The Every 5 years beginning in 2025, the Environmental
4		Protection Agency, Illinois Power Agency, and Illinois
5		Commerce Commission shall jointly prepare, and release
6		publicly, a report to the General Assembly that examines the
7		State's current progress toward its renewable energy resource
8		development goals, the status of CO2e and copollutant
9		emissions reductions, the current status and progress toward
10		developing and implementing green hydrogen technologies, the
11		current and projected status of electric resource adequacy and
12		reliability throughout the State for the period beginning 5
13		years ahead, and proposed solutions for any findings. The
14		Environmental Protection Agency, Illinois Power Agency, and
15		Illinois Commerce Commission shall consult PJM
16		Interconnection, LLC and Midcontinent Independent System
17		Operator, Inc., or their respective successor organizations
18		regarding forecasted resource adequacy and reliability needs,
19		anticipated new generation interconnection, new transmission
20		development or upgrades, and any announced large GHG-emitting
21		unit closure dates and include this information in the report.
22		The report shall be released publicly by no later than
23		December 15 of the year it is prepared. If the Environmental
24		Protection Agency, Illinois Power Agency, and Illinois
25		Commerce Commission jointly conclude in the report that the
26		data from the regional grid operators, the pace of renewable

SB0025 Enrolled - 918 - LRB104 07069 BAB 17106 b
1		energy development, the pace of development of energy storage
2		and demand response utilization, transmission capacity, and
3		the CO2e and copollutant emissions reductions required by
4		subsection (i) or (k-5) reasonably demonstrate that a resource
5		adequacy shortfall will occur, including whether there will be
6		sufficient in-state capacity to meet the zonal requirements of
7		MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
8		regional transmission organizations, or that the regional
9		transmission operators determine that a reliability violation
10		will occur during the time frame the study is evaluating, then
11		the Illinois Power Agency, in conjunction with the
12		Environmental Protection Agency shall develop a plan to reduce
13		or delay CO2e and copollutant emissions reductions
14		requirements only to the extent and for the duration necessary
15		to meet the resource adequacy and reliability needs of the
16		State, including allowing any plants whose emission reduction
17		deadline has been identified in the plan as creating a
18		reliability concern to continue operating, including operating
19		with reduced emissions or as emergency backup where
20		appropriate. The plan shall also consider the use of renewable
21		energy, energy storage, demand response, transmission
22		development, or other strategies to resolve the identified
23		resource adequacy shortfall or reliability violation.
24		(1) In developing the plan, the Environmental
25		Protection Agency and the Illinois Power Agency shall hold
26		at least one workshop open to, and accessible at a time and

SB0025 Enrolled - 919 - LRB104 07069 BAB 17106 b
1		place convenient to, the public and shall consider any
2		comments made by stakeholders or the public. Upon
3		development of the plan, copies of the plan shall be
4		posted and made publicly available on the Environmental
5		Protection Agency's, the Illinois Power Agency's, and the
6		Illinois Commerce Commission's websites. All interested
7		parties shall have 60 days following the date of posting
8		to provide comment to the Environmental Protection Agency
9		and the Illinois Power Agency on the plan. All comments
10		submitted to the Environmental Protection Agency and the
11		Illinois Power Agency shall be encouraged to be specific,
12		supported by data or other detailed analyses, and, if
13		objecting to all or a portion of the plan, accompanied by
14		specific alternative wording or proposals. All comments
15		shall be posted on the Environmental Protection Agency's,
16		the Illinois Power Agency's, and the Illinois Commerce
17		Commission's websites. Within 30 days following the end of
18		the 60-day review period, the Environmental Protection
19		Agency and the Illinois Power Agency shall revise the plan
20		as necessary based on the comments received and file its
21		revised plan with the Illinois Commerce Commission for
22		approval.
23		(2) Within 60 days after the filing of the revised
24		plan at the Illinois Commerce Commission, any person
25		objecting to the plan shall file an objection with the
26		Illinois Commerce Commission. Within 30 days after the

SB0025 Enrolled - 920 - LRB104 07069 BAB 17106 b
1		expiration of the comment period, the Illinois Commerce
2		Commission shall determine whether an evidentiary hearing
3		is necessary. The Illinois Commerce Commission shall also
4		host 3 public hearings within 90 days after the plan is
5		filed. Following the evidentiary and public hearings, the
6		Illinois Commerce Commission shall enter its order
7		approving or approving with modifications the reliability
8		mitigation plan within 180 days.
9		(3) The Illinois Commerce Commission shall only
10		approve the plan if the Illinois Commerce Commission
11		determines that it will resolve the resource adequacy or
12		reliability deficiency identified in the reliability
13		mitigation plan at the least amount of CO2e and copollutant
14		emissions, taking into consideration the emissions impacts
15		on environmental justice communities, and that it will
16		ensure adequate, reliable, affordable, efficient, and
17		environmentally sustainable electric service at the lowest
18		total cost over time, taking into account the impact of
19		increases in emissions.
20		(4) If the resource adequacy or reliability deficiency
21		identified in the reliability mitigation plan is resolved
22		or reduced, the Environmental Protection Agency and the
23		Illinois Power Agency may file an amended plan adjusting
24		the reduction or delay in CO2e and copollutant emission
25		reduction requirements identified in the plan.
26		(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)

SB0025 Enrolled - 921 - LRB104 07069 BAB 17106 b
1		(415 ILCS 5/25)  (from Ch. 111 1/2, par. 1025)
2		Sec. 25. The Board, pursuant to the procedures prescribed
3		in Title VII of this Act, may adopt regulations prescribing
4		limitations on noise emissions beyond the boundaries of the
5		property of any person and prescribing requirements and
6		standards for equipment and procedures for monitoring noise
7		and the collection, reporting and retention of data resulting
8		from such monitoring.
9		The Board shall, by regulations under this Section,
10		categorize the types and sources of noise emissions that
11		unreasonably interfere with the enjoyment of life, or with any
12		lawful business, or activity, and shall prescribe for each
13		such category the maximum permissible limits on such noise
14		emissions. The Board shall secure the co-operation of the
15		Department in determining the categories of noise emission and
16		the technological and economic feasibility of such noise level
17		limits.
18		In connection with any commercial solar energy facility or
19		commercial wind energy facility, the fee simple owner of a
20		participating property, participating residence,
21		nonparticipating property, nonparticipating residence, or any
22		combination of those properties and residences may enter into
23		a written waiver agreement or other similar instrument
24		pursuant to which the owner agrees to waive the enforcement,
25		either entirely or on a limited basis, of the rules and

SB0025 Enrolled - 922 - LRB104 07069 BAB 17106 b
1		regulations that are adopted under this Section or Section 24
2		of this Act and that pertain to the facility. Such a waiver
3		shall be recorded in the Office of the Recorder of the county
4		in which the participating property, participating residence,
5		nonparticipating property, or nonparticipating residence is
6		located and, once recorded, shall be binding upon and
7		constructive notice to all current and future owners,
8		residents, lessees, invitees, and users of the property so
9		long as the recorded waiver includes a legal description or
10		location of the affected property and a reference that it
11		waives certain provisions of this Act and their enforcement,
12		as well as certain rules and regulations adopted under this
13		Act and their enforcement. Upon the recording of such a
14		waiver, in addition to the owner, the Board, Agency, or other
15		person shall not be permitted to enforce the rules and
16		regulations adopted under this Section or Section 24, and
17		those rules and regulations shall not be effective, to the
18		extent the rules and regulations for the affected property
19		have been waived under this Section, against the facility that
20		is the subject of the recorded waiver. An owner of any
21		participating residence or nonparticipating residence shall
22		disclose the existence of such a waiver to any lessee before
23		entering any new lease for the residence. A seller of any
24		participating property, participating residence,
25		nonparticipating property, nonparticipating residence, or any
26		combination of those properties and residences shall disclose

SB0025 Enrolled - 923 - LRB104 07069 BAB 17106 b
1		the existence of the waiver before any sale or other transfer
2		of the property. If disclosure of the waiver occurs after the
3		buyer has made an offer to purchase the property, the seller
4		shall disclose the existence of the waiver before accepting
5		the buyer's offer and shall (1) allow the buyer an opportunity
6		to review the disclosure and (2) inform the buyer that the
7		buyer has the right to amend the buyer's offer. As used in this
8		Section, "commercial solar energy facility", "commercial wind
9		energy facility", "nonparticipating property",
10		"nonparticipating residence", "participating property", and
11		"participating residence" have the meanings given in
12		subsection (a) of Section 5-12020 of the Counties Code.
13		In establishing such limits, the Board, in addition to
14		considering those factors set forth in Section 27 of this Act,
15		shall consider the adverse ecological effects on and
16		interference with the enjoyment of natural, scenic, wilderness
17		or other outdoor recreational areas, parks, and forests
18		occasioned by noise emissions from automotive, mechanical, and
19		other sources and may establish lower permissible noise levels
20		applicable to sources in such outdoor recreational uses.
21		No Board standards for monitoring noise or regulations
22		prescribing limitations on noise emissions shall apply to any
23		organized amateur or professional sporting activity except as
24		otherwise provided in this Section. Baseball, football or
25		soccer sporting events played during nighttime hours, by
26		professional athletes, in a city with more than 1,000,000

SB0025 Enrolled - 924 - LRB104 07069 BAB 17106 b
1		inhabitants, in a stadium at which such nighttime events were
2		not played prior to July 1, 1982, shall be subject to nighttime
3		noise emission regulations promulgated by the Illinois
4		Pollution Control Board; however, the following events shall
5		not be subject to such regulations:
6		(1) baseball World Series games, league championship
7		series games and other playoff games played after the
8		conclusion of the regular season, and baseball All Star games;
9		and
10		(2) sporting events or other events held in a stadium
11		which replaces a stadium not subject to such regulations and
12		constructed within 1500 yards of the original stadium by the
13		Illinois Sports Facilities Authority.
14		For purposes of this Section and Section 24, "beyond the
15		boundaries of his property" or "beyond the boundaries of the
16		property of any person" includes personal property as well as
17		real property.
18		(Source: P.A. 89-445, eff. 2-7-96.)
19		(415 ILCS 5/39)  (from Ch. 111 1/2, par. 1039)
20		Sec. 39. Issuance of permits; procedures.
21		(a) When the Board has by regulation required a permit for
22		the construction, installation, or operation of any type of
23		facility, equipment, vehicle, vessel, or aircraft, the
24		applicant shall apply to the Agency for such permit and it
25		shall be the duty of the Agency to issue such a permit upon

SB0025 Enrolled - 925 - LRB104 07069 BAB 17106 b
1		proof by the applicant that the facility, equipment, vehicle,
2		vessel, or aircraft will not cause a violation of this Act or
3		of regulations hereunder. The Agency shall adopt such
4		procedures as are necessary to carry out its duties under this
5		Section. In making its determinations on permit applications
6		under this Section the Agency may consider prior adjudications
7		of noncompliance with this Act by the applicant that involved
8		a release of a contaminant into the environment. In granting
9		permits, the Agency may impose reasonable conditions
10		specifically related to the applicant's past compliance
11		history with this Act as necessary to correct, detect, or
12		prevent noncompliance. The Agency may impose such other
13		conditions as may be necessary to accomplish the purposes of
14		this Act, and as are not inconsistent with the regulations
15		promulgated by the Board hereunder. Except as otherwise
16		provided in this Act, a bond or other security shall not be
17		required as a condition for the issuance of a permit. If the
18		Agency denies any permit under this Section, the Agency shall
19		transmit to the applicant within the time limitations of this
20		Section specific, detailed statements as to the reasons the
21		permit application was denied. Such statements shall include,
22		but not be limited to, the following:
23		(i) the Sections of this Act which may be violated if
24		the permit were granted;
25		(ii) the provision of the regulations, promulgated
26		under this Act, which may be violated if the permit were

SB0025 Enrolled - 926 - LRB104 07069 BAB 17106 b
1		granted;
2		(iii) the specific type of information, if any, which
3		the Agency deems the applicant did not provide the Agency;
4		and
5		(iv) a statement of specific reasons why the Act and
6		the regulations might not be met if the permit were
7		granted.
8		If there is no final action by the Agency within 90 days
9		after the filing of the application for permit, the applicant
10		may deem the permit issued; except that this time period shall
11		be extended to 180 days when (1) notice and opportunity for
12		public hearing are required by State or federal law or
13		regulation, (2) the application which was filed is for any
14		permit to develop a landfill subject to issuance pursuant to
15		this subsection, or (3) the application that was filed is for a
16		MSWLF unit required to issue public notice under subsection
17		(p) of Section 39. The 90-day and 180-day time periods for the
18		Agency to take final action do not apply to NPDES permit
19		applications under subsection (b) of this Section, to RCRA
20		permit applications under subsection (d) of this Section, to
21		UIC permit applications under subsection (e) of this Section,
22		or to CCR surface impoundment applications under subsection
23		(y) of this Section.
24		The Agency shall publish notice of all final permit
25		determinations for development permits for MSWLF units and for
26		significant permit modifications for lateral expansions for

SB0025 Enrolled - 927 - LRB104 07069 BAB 17106 b
1		existing MSWLF units one time in a newspaper of general
2		circulation in the county in which the unit is or is proposed
3		to be located.
4		After January 1, 1994 and until July 1, 1998, operating
5		permits issued under this Section by the Agency for sources of
6		air pollution permitted to emit less than 25 tons per year of
7		any combination of regulated air pollutants, as defined in
8		Section 39.5 of this Act, shall be required to be renewed only
9		upon written request by the Agency consistent with applicable
10		provisions of this Act and regulations promulgated hereunder.
11		Such operating permits shall expire 180 days after the date of
12		such a request. The Board shall revise its regulations for the
13		existing State air pollution operating permit program
14		consistent with this provision by January 1, 1994.
15		After June 30, 1998, operating permits issued under this
16		Section by the Agency for sources of air pollution that are not
17		subject to Section 39.5 of this Act and are not required to
18		have a federally enforceable State operating permit shall be
19		required to be renewed only upon written request by the Agency
20		consistent with applicable provisions of this Act and its
21		rules. Such operating permits shall expire 180 days after the
22		date of such a request. Before July 1, 1998, the Board shall
23		revise its rules for the existing State air pollution
24		operating permit program consistent with this paragraph and
25		shall adopt rules that require a source to demonstrate that it
26		qualifies for a permit under this paragraph.

SB0025 Enrolled - 928 - LRB104 07069 BAB 17106 b
1		Each air pollution construction permit for diesel powered
2		backup generators to a source that is a data center, as defined
3		in subsection (c) of Section 605-1025 of the Department of
4		Commerce and Economic Opportunity Law of the Civil
5		Administrative Code of Illinois, that is applied for 6 months
6		after the effective date of this amendatory Act of the 104th
7		General Assembly and that is required to have a federally
8		enforceable State operating permit or a Clean Air Act Permit
9		Program permit shall, in addition to any other applicable
10		requirements, require each backup generator to: (i) meet
11		standards at least as protective as Tier 4 standards for
12		non-road diesel engines set out by the United States
13		Environmental Protection Agency in 40 CFR 1039, as it exists
14		on the effective date of this amendatory Act of the 104th
15		General Assembly, and (ii) operate solely as an emergency or
16		standby unit in accordance with 35 Ill. Adm. Code 211.1920, as
17		it exists on the effective date of this amendatory Act of the
18		104th General Assembly. If a diesel powered backup generator
19		becomes out of compliance with the Tier 4 standards for
20		non-road compression-ignition engines during a power outage,
21		the backup generator may (1) continue to operate for up to 24
22		sequential hours after becoming noncompliant with the Tier 4
23		standards or (2) operate when compliance is achieved.
24		Notwithstanding any provision of law to the contrary,
25		operation of the backup generator for up to 24 sequential
26		hours after becoming noncompliant with the Tier 4 standards

SB0025 Enrolled - 929 - LRB104 07069 BAB 17106 b
1		shall not be considered a violation of the permit.
2		Each air pollution construction permit for natural gas
3		powered backup generators for a source that is a data center,
4		as defined in subsection (c) of Section 605-1025 of the
5		Department of Commerce and Economic Opportunity Law of the
6		Civil Administrative Code of Illinois, that is applied for 6
7		months after the effective date of this amendatory Act of the
8		104th General Assembly and that is required to have a
9		federally enforceable State operating permit or a Clean Air
10		Act Permit Program permit shall, in addition to any other
11		applicable requirements, require each backup generator to: (i)
12		meet standards at least as protective as Tier 2 standards for
13		non-road large spark-ignition engines set out by the United
14		States Environmental Protection Agency in 40 CFR 1048, as it
15		exists on the effective date of this amendatory Act of the
16		104th General Assembly, and (ii) operate solely as an
17		emergency or standby unit in accordance with 35 Ill. Adm. Code
18		211.1920, as it exists on the effective date of this
19		amendatory Act of the 104th General Assembly. If a natural gas
20		powered backup generator becomes out of compliance with the
21		Tier 2 standards for non-road large spark-ignition engines
22		during a power outage, the backup generator may (1) continue
23		to operate for up to 24 sequential hours after becoming
24		noncompliant with the Tier 2 standards or (2) operate when
25		compliance is achieved. Notwithstanding any provision of law
26		to the contrary, operation of the backup generator for up to 24

SB0025 Enrolled - 930 - LRB104 07069 BAB 17106 b
1		sequential hours after becoming noncompliant with the Tier 2
2		standards shall not be considered a violation of the permit.
3		(b) The Agency may issue NPDES permits exclusively under
4		this subsection for the discharge of contaminants from point
5		sources into navigable waters, all as defined in the Federal
6		Water Pollution Control Act, as now or hereafter amended,
7		within the jurisdiction of the State, or into any well.
8		All NPDES permits shall contain those terms and
9		conditions, including, but not limited to, schedules of
10		compliance, which may be required to accomplish the purposes
11		and provisions of this Act.
12		The Agency may issue general NPDES permits for discharges
13		from categories of point sources which are subject to the same
14		permit limitations and conditions. Such general permits may be
15		issued without individual applications and shall conform to
16		regulations promulgated under Section 402 of the Federal Water
17		Pollution Control Act, as now or hereafter amended.
18		The Agency may include, among such conditions, effluent
19		limitations and other requirements established under this Act,
20		Board regulations, the Federal Water Pollution Control Act, as
21		now or hereafter amended, and regulations pursuant thereto,
22		and schedules for achieving compliance therewith at the
23		earliest reasonable date.
24		The Agency shall adopt filing requirements and procedures
25		which are necessary and appropriate for the issuance of NPDES
26		permits, and which are consistent with the Act or regulations

SB0025 Enrolled - 931 - LRB104 07069 BAB 17106 b
1		adopted by the Board, and with the Federal Water Pollution
2		Control Act, as now or hereafter amended, and regulations
3		pursuant thereto.
4		The Agency, subject to any conditions which may be
5		prescribed by Board regulations, may issue NPDES permits to
6		allow discharges beyond deadlines established by this Act or
7		by regulations of the Board without the requirement of a
8		variance, subject to the Federal Water Pollution Control Act,
9		as now or hereafter amended, and regulations pursuant thereto.
10		(c) Except for those facilities owned or operated by
11		sanitary districts organized under the Metropolitan Water
12		Reclamation District Act, no permit for the development or
13		construction of a new pollution control facility may be
14		granted by the Agency unless the applicant submits proof to
15		the Agency that the location of the facility has been approved
16		by the county board of the county if in an unincorporated area,
17		or the governing body of the municipality when in an
18		incorporated area, in which the facility is to be located in
19		accordance with Section 39.2 of this Act. For purposes of this
20		subsection (c), and for purposes of Section 39.2 of this Act,
21		the appropriate county board or governing body of the
22		municipality shall be the county board of the county or the
23		governing body of the municipality in which the facility is to
24		be located as of the date when the application for siting
25		approval is filed.
26		In the event that siting approval granted pursuant to

SB0025 Enrolled - 932 - LRB104 07069 BAB 17106 b
1		Section 39.2 has been transferred to a subsequent owner or
2		operator, that subsequent owner or operator may apply to the
3		Agency for, and the Agency may grant, a development or
4		construction permit for the facility for which local siting
5		approval was granted. Upon application to the Agency for a
6		development or construction permit by that subsequent owner or
7		operator, the permit applicant shall cause written notice of
8		the permit application to be served upon the appropriate
9		county board or governing body of the municipality that
10		granted siting approval for that facility and upon any party
11		to the siting proceeding pursuant to which siting approval was
12		granted. In that event, the Agency shall conduct an evaluation
13		of the subsequent owner or operator's prior experience in
14		waste management operations in the manner conducted under
15		subsection (i) of Section 39 of this Act.
16		Beginning August 20, 1993, if the pollution control
17		facility consists of a hazardous or solid waste disposal
18		facility for which the proposed site is located in an
19		unincorporated area of a county with a population of less than
20		100,000 and includes all or a portion of a parcel of land that
21		was, on April 1, 1993, adjacent to a municipality having a
22		population of less than 5,000, then the local siting review
23		required under this subsection (c) in conjunction with any
24		permit applied for after that date shall be performed by the
25		governing body of that adjacent municipality rather than the
26		county board of the county in which the proposed site is

SB0025 Enrolled - 933 - LRB104 07069 BAB 17106 b
1		located; and for the purposes of that local siting review, any
2		references in this Act to the county board shall be deemed to
3		mean the governing body of that adjacent municipality;
4		provided, however, that the provisions of this paragraph shall
5		not apply to any proposed site which was, on April 1, 1993,
6		owned in whole or in part by another municipality.
7		In the case of a pollution control facility for which a
8		development permit was issued before November 12, 1981, if an
9		operating permit has not been issued by the Agency prior to
10		August 31, 1989 for any portion of the facility, then the
11		Agency may not issue or renew any development permit nor issue
12		an original operating permit for any portion of such facility
13		unless the applicant has submitted proof to the Agency that
14		the location of the facility has been approved by the
15		appropriate county board or municipal governing body pursuant
16		to Section 39.2 of this Act.
17		After January 1, 1994, if a solid waste disposal facility,
18		any portion for which an operating permit has been issued by
19		the Agency, has not accepted waste disposal for 5 or more
20		consecutive calendar years, before that facility may accept
21		any new or additional waste for disposal, the owner and
22		operator must obtain a new operating permit under this Act for
23		that facility unless the owner and operator have applied to
24		the Agency for a permit authorizing the temporary suspension
25		of waste acceptance. The Agency may not issue a new operation
26		permit under this Act for the facility unless the applicant

SB0025 Enrolled - 934 - LRB104 07069 BAB 17106 b
1		has submitted proof to the Agency that the location of the
2		facility has been approved or re-approved by the appropriate
3		county board or municipal governing body under Section 39.2 of
4		this Act after the facility ceased accepting waste.
5		Except for those facilities owned or operated by sanitary
6		districts organized under the Metropolitan Water Reclamation
7		District Act, and except for new pollution control facilities
8		governed by Section 39.2, and except for fossil fuel mining
9		facilities, the granting of a permit under this Act shall not
10		relieve the applicant from meeting and securing all necessary
11		zoning approvals from the unit of government having zoning
12		jurisdiction over the proposed facility.
13		Before beginning construction on any new sewage treatment
14		plant or sludge drying site to be owned or operated by a
15		sanitary district organized under the Metropolitan Water
16		Reclamation District Act for which a new permit (rather than
17		the renewal or amendment of an existing permit) is required,
18		such sanitary district shall hold a public hearing within the
19		municipality within which the proposed facility is to be
20		located, or within the nearest community if the proposed
21		facility is to be located within an unincorporated area, at
22		which information concerning the proposed facility shall be
23		made available to the public, and members of the public shall
24		be given the opportunity to express their views concerning the
25		proposed facility.
26		The Agency may issue a permit for a municipal waste

SB0025 Enrolled - 935 - LRB104 07069 BAB 17106 b
1		transfer station without requiring approval pursuant to
2		Section 39.2 provided that the following demonstration is
3		made:
4		(1) the municipal waste transfer station was in
5		existence on or before January 1, 1979 and was in
6		continuous operation from January 1, 1979 to January 1,
7		1993;
8		(2) the operator submitted a permit application to the
9		Agency to develop and operate the municipal waste transfer
10		station during April of 1994;
11		(3) the operator can demonstrate that the county board
12		of the county, if the municipal waste transfer station is
13		in an unincorporated area, or the governing body of the
14		municipality, if the station is in an incorporated area,
15		does not object to resumption of the operation of the
16		station; and
17		(4) the site has local zoning approval.
18		(d) The Agency may issue RCRA permits exclusively under
19		this subsection to persons owning or operating a facility for
20		the treatment, storage, or disposal of hazardous waste as
21		defined under this Act. Subsection (y) of this Section, rather
22		than this subsection (d), shall apply to permits issued for
23		CCR surface impoundments.
24		All RCRA permits shall contain those terms and conditions,
25		including, but not limited to, schedules of compliance, which
26		may be required to accomplish the purposes and provisions of

SB0025 Enrolled - 936 - LRB104 07069 BAB 17106 b
1		this Act. The Agency may include among such conditions
2		standards and other requirements established under this Act,
3		Board regulations, the Resource Conservation and Recovery Act
4		of 1976 (P.L. 94-580), as amended, and regulations pursuant
5		thereto, and may include schedules for achieving compliance
6		therewith as soon as possible. The Agency shall require that a
7		performance bond or other security be provided as a condition
8		for the issuance of a RCRA permit.
9		In the case of a permit to operate a hazardous waste or PCB
10		incinerator as defined in subsection (k) of Section 44, the
11		Agency shall require, as a condition of the permit, that the
12		operator of the facility perform such analyses of the waste to
13		be incinerated as may be necessary and appropriate to ensure
14		the safe operation of the incinerator.
15		The Agency shall adopt filing requirements and procedures
16		which are necessary and appropriate for the issuance of RCRA
17		permits, and which are consistent with the Act or regulations
18		adopted by the Board, and with the Resource Conservation and
19		Recovery Act of 1976 (P.L. 94-580), as amended, and
20		regulations pursuant thereto.
21		The applicant shall make available to the public for
22		inspection all documents submitted by the applicant to the
23		Agency in furtherance of an application, with the exception of
24		trade secrets, at the office of the county board or governing
25		body of the municipality. Such documents may be copied upon
26		payment of the actual cost of reproduction during regular

SB0025 Enrolled - 937 - LRB104 07069 BAB 17106 b
1		business hours of the local office. The Agency shall issue a
2		written statement concurrent with its grant or denial of the
3		permit explaining the basis for its decision.
4		(e) The Agency may issue UIC permits exclusively under
5		this subsection to persons owning or operating a facility for
6		the underground injection of contaminants as defined under
7		this Act.
8		All UIC permits shall contain those terms and conditions,
9		including, but not limited to, schedules of compliance, which
10		may be required to accomplish the purposes and provisions of
11		this Act. The Agency may include among such conditions
12		standards and other requirements established under this Act,
13		Board regulations, the Safe Drinking Water Act (P.L. 93-523),
14		as amended, and regulations pursuant thereto, and may include
15		schedules for achieving compliance therewith. The Agency shall
16		require that a performance bond or other security be provided
17		as a condition for the issuance of a UIC permit.
18		The Agency shall adopt filing requirements and procedures
19		which are necessary and appropriate for the issuance of UIC
20		permits, and which are consistent with the Act or regulations
21		adopted by the Board, and with the Safe Drinking Water Act
22		(P.L. 93-523), as amended, and regulations pursuant thereto.
23		The applicant shall make available to the public for
24		inspection all documents submitted by the applicant to the
25		Agency in furtherance of an application, with the exception of
26		trade secrets, at the office of the county board or governing

SB0025 Enrolled - 938 - LRB104 07069 BAB 17106 b
1		body of the municipality. Such documents may be copied upon
2		payment of the actual cost of reproduction during regular
3		business hours of the local office. The Agency shall issue a
4		written statement concurrent with its grant or denial of the
5		permit explaining the basis for its decision.
6		(f) In making any determination pursuant to Section 9.1 of
7		this Act:
8		(1) The Agency shall have authority to make the
9		determination of any question required to be determined by
10		the Clean Air Act, as now or hereafter amended, this Act,
11		or the regulations of the Board, including the
12		determination of the Lowest Achievable Emission Rate,
13		Maximum Achievable Control Technology, or Best Available
14		Control Technology, consistent with the Board's
15		regulations, if any.
16		(2) The Agency shall adopt requirements as necessary
17		to implement public participation procedures, including,
18		but not limited to, public notice, comment, and an
19		opportunity for hearing, which must accompany the
20		processing of applications for PSD permits. The Agency
21		shall briefly describe and respond to all significant
22		comments on the draft permit raised during the public
23		comment period or during any hearing. The Agency may group
24		related comments together and provide one unified response
25		for each issue raised.
26		(3) Any complete permit application submitted to the

SB0025 Enrolled - 939 - LRB104 07069 BAB 17106 b
1		Agency under this subsection for a PSD permit shall be
2		granted or denied by the Agency not later than one year
3		after the filing of such completed application.
4		(4) The Agency shall, after conferring with the
5		applicant, give written notice to the applicant of its
6		proposed decision on the application, including the terms
7		and conditions of the permit to be issued and the facts,
8		conduct, or other basis upon which the Agency will rely to
9		support its proposed action.
10		(g) The Agency shall include as conditions upon all
11		permits issued for hazardous waste disposal sites such
12		restrictions upon the future use of such sites as are
13		reasonably necessary to protect public health and the
14		environment, including permanent prohibition of the use of
15		such sites for purposes which may create an unreasonable risk
16		of injury to human health or to the environment. After
17		administrative and judicial challenges to such restrictions
18		have been exhausted, the Agency shall file such restrictions
19		of record in the Office of the Recorder of the county in which
20		the hazardous waste disposal site is located.
21		(h) A hazardous waste stream may not be deposited in a
22		permitted hazardous waste site unless specific authorization
23		is obtained from the Agency by the generator and disposal site
24		owner and operator for the deposit of that specific hazardous
25		waste stream. The Agency may grant specific authorization for
26		disposal of hazardous waste streams only after the generator

SB0025 Enrolled - 940 - LRB104 07069 BAB 17106 b
1		has reasonably demonstrated that, considering technological
2		feasibility and economic reasonableness, the hazardous waste
3		cannot be reasonably recycled for reuse, nor incinerated or
4		chemically, physically, or biologically treated so as to
5		neutralize the hazardous waste and render it nonhazardous. In
6		granting authorization under this Section, the Agency may
7		impose such conditions as may be necessary to accomplish the
8		purposes of the Act and are consistent with this Act and
9		regulations promulgated by the Board hereunder. If the Agency
10		refuses to grant authorization under this Section, the
11		applicant may appeal as if the Agency refused to grant a
12		permit, pursuant to the provisions of subsection (a) of
13		Section 40 of this Act. For purposes of this subsection (h),
14		the term "generator" has the meaning given in Section 3.205 of
15		this Act, unless: (1) the hazardous waste is treated,
16		incinerated, or partially recycled for reuse prior to
17		disposal, in which case the last person who treats,
18		incinerates, or partially recycles the hazardous waste prior
19		to disposal is the generator; or (2) the hazardous waste is
20		from a response action, in which case the person performing
21		the response action is the generator. This subsection (h) does
22		not apply to any hazardous waste that is restricted from land
23		disposal under 35 Ill. Adm. Code 728.
24		(i) Before issuing any RCRA permit, any permit for a waste
25		storage site, sanitary landfill, waste disposal site, waste
26		transfer station, waste treatment facility, waste incinerator,

SB0025 Enrolled - 941 - LRB104 07069 BAB 17106 b
1		or any waste-transportation operation, any permit or interim
2		authorization for a clean construction or demolition debris
3		fill operation, or any permit required under subsection (d-5)
4		of Section 55, the Agency shall conduct an evaluation of the
5		prospective owner's or operator's prior experience in waste
6		management operations, clean construction or demolition debris
7		fill operations, and tire storage site management. The Agency
8		may deny such a permit, or deny or revoke interim
9		authorization, if the prospective owner or operator or any
10		employee or officer of the prospective owner or operator has a
11		history of:
12		(1) repeated violations of federal, State, or local
13		laws, regulations, standards, or ordinances in the
14		operation of waste management facilities or sites, clean
15		construction or demolition debris fill operation
16		facilities or sites, or tire storage sites; or
17		(2) conviction in this or another State of any crime
18		which is a felony under the laws of this State, or
19		conviction of a felony in a federal court; or conviction
20		in this or another state or federal court of any of the
21		following crimes: forgery, official misconduct, bribery,
22		perjury, or knowingly submitting false information under
23		any environmental law, regulation, or permit term or
24		condition; or
25		(3) proof of gross carelessness or incompetence in
26		handling, storing, processing, transporting, or disposing

SB0025 Enrolled - 942 - LRB104 07069 BAB 17106 b
1		of waste, clean construction or demolition debris, or used
2		or waste tires, or proof of gross carelessness or
3		incompetence in using clean construction or demolition
4		debris as fill.
5		(i-5) Before issuing any permit or approving any interim
6		authorization for a clean construction or demolition debris
7		fill operation in which any ownership interest is transferred
8		between January 1, 2005, and the effective date of the
9		prohibition set forth in Section 22.52 of this Act, the Agency
10		shall conduct an evaluation of the operation if any previous
11		activities at the site or facility may have caused or allowed
12		contamination of the site. It shall be the responsibility of
13		the owner or operator seeking the permit or interim
14		authorization to provide to the Agency all of the information
15		necessary for the Agency to conduct its evaluation. The Agency
16		may deny a permit or interim authorization if previous
17		activities at the site may have caused or allowed
18		contamination at the site, unless such contamination is
19		authorized under any permit issued by the Agency.
20		(j) The issuance under this Act of a permit to engage in
21		the surface mining of any resources other than fossil fuels
22		shall not relieve the permittee from its duty to comply with
23		any applicable local law regulating the commencement,
24		location, or operation of surface mining facilities.
25		(k) A development permit issued under subsection (a) of
26		Section 39 for any facility or site which is required to have a

SB0025 Enrolled - 943 - LRB104 07069 BAB 17106 b
1		permit under subsection (d) of Section 21 shall expire at the
2		end of 2 calendar years from the date upon which it was issued,
3		unless within that period the applicant has taken action to
4		develop the facility or the site. In the event that review of
5		the conditions of the development permit is sought pursuant to
6		Section 40 or 41, or permittee is prevented from commencing
7		development of the facility or site by any other litigation
8		beyond the permittee's control, such two-year period shall be
9		deemed to begin on the date upon which such review process or
10		litigation is concluded.
11		(l) No permit shall be issued by the Agency under this Act
12		for construction or operation of any facility or site located
13		within the boundaries of any setback zone established pursuant
14		to this Act, where such construction or operation is
15		prohibited.
16		(m) The Agency may issue permits to persons owning or
17		operating a facility for composting landscape waste. In
18		granting such permits, the Agency may impose such conditions
19		as may be necessary to accomplish the purposes of this Act, and
20		as are not inconsistent with applicable regulations
21		promulgated by the Board. Except as otherwise provided in this
22		Act, a bond or other security shall not be required as a
23		condition for the issuance of a permit. If the Agency denies
24		any permit pursuant to this subsection, the Agency shall
25		transmit to the applicant within the time limitations of this
26		subsection specific, detailed statements as to the reasons the

SB0025 Enrolled - 944 - LRB104 07069 BAB 17106 b
1		permit application was denied. Such statements shall include
2		but not be limited to the following:
3		(1) the Sections of this Act that may be violated if
4		the permit were granted;
5		(2) the specific regulations promulgated pursuant to
6		this Act that may be violated if the permit were granted;
7		(3) the specific information, if any, the Agency deems
8		the applicant did not provide in its application to the
9		Agency; and
10		(4) a statement of specific reasons why the Act and
11		the regulations might be violated if the permit were
12		granted.
13		If no final action is taken by the Agency within 90 days
14		after the filing of the application for permit, the applicant
15		may deem the permit issued. Any applicant for a permit may
16		waive the 90-day limitation by filing a written statement with
17		the Agency.
18		The Agency shall issue permits for such facilities upon
19		receipt of an application that includes a legal description of
20		the site, a topographic map of the site drawn to the scale of
21		200 feet to the inch or larger, a description of the operation,
22		including the area served, an estimate of the volume of
23		materials to be processed, and documentation that:
24		(1) the facility includes a setback of at least 200
25		feet from the nearest potable water supply well;
26		(2) the facility is located outside the boundary of

SB0025 Enrolled - 945 - LRB104 07069 BAB 17106 b
1		the 10-year floodplain or the site will be floodproofed;
2		(3) the facility is located so as to minimize
3		incompatibility with the character of the surrounding
4		area, including at least a 200 foot setback from any
5		residence, and in the case of a facility that is developed
6		or the permitted composting area of which is expanded
7		after November 17, 1991, the composting area is located at
8		least 1/8 mile from the nearest residence (other than a
9		residence located on the same property as the facility);
10		(4) the design of the facility will prevent any
11		compost material from being placed within 5 feet of the
12		water table, will adequately control runoff from the site,
13		and will collect and manage any leachate that is generated
14		on the site;
15		(5) the operation of the facility will include
16		appropriate dust and odor control measures, limitations on
17		operating hours, appropriate noise control measures for
18		shredding, chipping and similar equipment, management
19		procedures for composting, containment and disposal of
20		non-compostable wastes, procedures to be used for
21		terminating operations at the site, and recordkeeping
22		sufficient to document the amount of materials received,
23		composted, and otherwise disposed of; and
24		(6) the operation will be conducted in accordance with
25		any applicable rules adopted by the Board.
26		The Agency shall issue renewable permits of not longer

SB0025 Enrolled - 946 - LRB104 07069 BAB 17106 b
1		than 10 years in duration for the composting of landscape
2		wastes, as defined in Section 3.155 of this Act, based on the
3		above requirements.
4		The operator of any facility permitted under this
5		subsection (m) must submit a written annual statement to the
6		Agency on or before April 1 of each year that includes an
7		estimate of the amount of material, in tons, received for
8		composting.
9		(n) The Agency shall issue permits jointly with the
10		Department of Transportation for the dredging or deposit of
11		material in Lake Michigan in accordance with Section 18 of the
12		Rivers, Lakes, and Streams Act.
13		(o) (Blank).
14		(p) (1) Any person submitting an application for a permit
15		for a new MSWLF unit or for a lateral expansion under
16		subsection (t) of Section 21 of this Act for an existing MSWLF
17		unit that has not received and is not subject to local siting
18		approval under Section 39.2 of this Act shall publish notice
19		of the application in a newspaper of general circulation in
20		the county in which the MSWLF unit is or is proposed to be
21		located. The notice must be published at least 15 days before
22		submission of the permit application to the Agency. The notice
23		shall state the name and address of the applicant, the
24		location of the MSWLF unit or proposed MSWLF unit, the nature
25		and size of the MSWLF unit or proposed MSWLF unit, the nature
26		of the activity proposed, the probable life of the proposed

SB0025 Enrolled - 947 - LRB104 07069 BAB 17106 b
1		activity, the date the permit application will be submitted,
2		and a statement that persons may file written comments with
3		the Agency concerning the permit application within 30 days
4		after the filing of the permit application unless the time
5		period to submit comments is extended by the Agency.
6		When a permit applicant submits information to the Agency
7		to supplement a permit application being reviewed by the
8		Agency, the applicant shall not be required to reissue the
9		notice under this subsection.
10		(2) The Agency shall accept written comments concerning
11		the permit application that are postmarked no later than 30
12		days after the filing of the permit application, unless the
13		time period to accept comments is extended by the Agency.
14		(3) Each applicant for a permit described in part (1) of
15		this subsection shall file a copy of the permit application
16		with the county board or governing body of the municipality in
17		which the MSWLF unit is or is proposed to be located at the
18		same time the application is submitted to the Agency. The
19		permit application filed with the county board or governing
20		body of the municipality shall include all documents submitted
21		to or to be submitted to the Agency, except trade secrets as
22		determined under Section 7.1 of this Act. The permit
23		application and other documents on file with the county board
24		or governing body of the municipality shall be made available
25		for public inspection during regular business hours at the
26		office of the county board or the governing body of the

SB0025 Enrolled - 948 - LRB104 07069 BAB 17106 b
1		municipality and may be copied upon payment of the actual cost
2		of reproduction.
3		(q) Within 6 months after July 12, 2011 (the effective
4		date of Public Act 97-95), the Agency, in consultation with
5		the regulated community, shall develop a web portal to be
6		posted on its website for the purpose of enhancing review and
7		promoting timely issuance of permits required by this Act. At
8		a minimum, the Agency shall make the following information
9		available on the web portal:
10		(1) Checklists and guidance relating to the completion
11		of permit applications, developed pursuant to subsection
12		(s) of this Section, which may include, but are not
13		limited to, existing instructions for completing the
14		applications and examples of complete applications. As the
15		Agency develops new checklists and develops guidance, it
16		shall supplement the web portal with those materials.
17		(2) Within 2 years after July 12, 2011 (the effective
18		date of Public Act 97-95), permit application forms or
19		portions of permit applications that can be completed and
20		saved electronically, and submitted to the Agency
21		electronically with digital signatures.
22		(3) Within 2 years after July 12, 2011 (the effective
23		date of Public Act 97-95), an online tracking system where
24		an applicant may review the status of its pending
25		application, including the name and contact information of
26		the permit analyst assigned to the application. Until the

SB0025 Enrolled - 949 - LRB104 07069 BAB 17106 b
1		online tracking system has been developed, the Agency
2		shall post on its website semi-annual permitting
3		efficiency tracking reports that include statistics on the
4		timeframes for Agency action on the following types of
5		permits received after July 12, 2011 (the effective date
6		of Public Act 97-95): air construction permits, new NPDES
7		permits and associated water construction permits, and
8		modifications of major NPDES permits and associated water
9		construction permits. The reports must be posted by
10		February 1 and August 1 each year and shall include:
11		(A) the number of applications received for each
12		type of permit, the number of applications on which
13		the Agency has taken action, and the number of
14		applications still pending; and
15		(B) for those applications where the Agency has
16		not taken action in accordance with the timeframes set
17		forth in this Act, the date the application was
18		received and the reasons for any delays, which may
19		include, but shall not be limited to, (i) the
20		application being inadequate or incomplete, (ii)
21		scientific or technical disagreements with the
22		applicant, USEPA, or other local, state, or federal
23		agencies involved in the permitting approval process,
24		(iii) public opposition to the permit, or (iv) Agency
25		staffing shortages. To the extent practicable, the
26		tracking report shall provide approximate dates when

SB0025 Enrolled - 950 - LRB104 07069 BAB 17106 b
1		cause for delay was identified by the Agency, when the
2		Agency informed the applicant of the problem leading
3		to the delay, and when the applicant remedied the
4		reason for the delay.
5		(r) Upon the request of the applicant, the Agency shall
6		notify the applicant of the permit analyst assigned to the
7		application upon its receipt.
8		(s) The Agency is authorized to prepare and distribute
9		guidance documents relating to its administration of this
10		Section and procedural rules implementing this Section.
11		Guidance documents prepared under this subsection shall not be
12		considered rules and shall not be subject to the Illinois
13		Administrative Procedure Act. Such guidance shall not be
14		binding on any party.
15		(t) Except as otherwise prohibited by federal law or
16		regulation, any person submitting an application for a permit
17		may include with the application suggested permit language for
18		Agency consideration. The Agency is not obligated to use the
19		suggested language or any portion thereof in its permitting
20		decision. If requested by the permit applicant, the Agency
21		shall meet with the applicant to discuss the suggested
22		language.
23		(u) If requested by the permit applicant, the Agency shall
24		provide the permit applicant with a copy of the draft permit
25		prior to any public review period.
26		(v) If requested by the permit applicant, the Agency shall

SB0025 Enrolled - 951 - LRB104 07069 BAB 17106 b
1		provide the permit applicant with a copy of the final permit
2		prior to its issuance.
3		(w) An air pollution permit shall not be required due to
4		emissions of greenhouse gases, as specified by Section 9.15 of
5		this Act.
6		(x) If, before the expiration of a State operating permit
7		that is issued pursuant to subsection (a) of this Section and
8		contains federally enforceable conditions limiting the
9		potential to emit of the source to a level below the major
10		source threshold for that source so as to exclude the source
11		from the Clean Air Act Permit Program, the Agency receives a
12		complete application for the renewal of that permit, then all
13		of the terms and conditions of the permit shall remain in
14		effect until final administrative action has been taken on the
15		application for the renewal of the permit.
16		(y) The Agency may issue permits exclusively under this
17		subsection to persons owning or operating a CCR surface
18		impoundment subject to Section 22.59.
19		(z) If a mass animal mortality event is declared by the
20		Department of Agriculture in accordance with the Animal
21		Mortality Act:
22		(1) the owner or operator responsible for the disposal
23		of dead animals is exempted from the following:
24		(i) obtaining a permit for the construction,
25		installation, or operation of any type of facility or
26		equipment issued in accordance with subsection (a) of

SB0025 Enrolled - 952 - LRB104 07069 BAB 17106 b
1		this Section;
2		(ii) obtaining a permit for open burning in
3		accordance with the rules adopted by the Board; and
4		(iii) registering the disposal of dead animals as
5		an eligible small source with the Agency in accordance
6		with Section 9.14 of this Act;
7		(2) as applicable, the owner or operator responsible
8		for the disposal of dead animals is required to obtain the
9		following permits:
10		(i) an NPDES permit in accordance with subsection
11		(b) of this Section;
12		(ii) a PSD permit or an NA NSR permit in accordance
13		with Section 9.1 of this Act;
14		(iii) a lifetime State operating permit or a
15		federally enforceable State operating permit, in
16		accordance with subsection (a) of this Section; or
17		(iv) a CAAPP permit, in accordance with Section
18		39.5 of this Act.
19		All CCR surface impoundment permits shall contain those
20		terms and conditions, including, but not limited to, schedules
21		of compliance, which may be required to accomplish the
22		purposes and provisions of this Act, Board regulations, the
23		Illinois Groundwater Protection Act and regulations pursuant
24		thereto, and the Resource Conservation and Recovery Act and
25		regulations pursuant thereto, and may include schedules for
26		achieving compliance therewith as soon as possible.

SB0025 Enrolled - 953 - LRB104 07069 BAB 17106 b
1		The Board shall adopt filing requirements and procedures
2		that are necessary and appropriate for the issuance of CCR
3		surface impoundment permits and that are consistent with this
4		Act or regulations adopted by the Board, and with the RCRA, as
5		amended, and regulations pursuant thereto.
6		The applicant shall make available to the public for
7		inspection all documents submitted by the applicant to the
8		Agency in furtherance of an application, with the exception of
9		trade secrets, on its public internet website as well as at the
10		office of the county board or governing body of the
11		municipality where CCR from the CCR surface impoundment will
12		be permanently disposed. Such documents may be copied upon
13		payment of the actual cost of reproduction during regular
14		business hours of the local office.
15		The Agency shall issue a written statement concurrent with
16		its grant or denial of the permit explaining the basis for its
17		decision.
18		(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22;
19		102-558, eff. 8-20-21; 102-813, eff. 5-13-22.)
20		Section 90-50. The Electric Vehicle Rebate Act is amended
21		by changing Sections 35, 40, and 45 and by adding Section 36 as
22		follows:
23		(415 ILCS 120/35)
24		Sec. 35. User fees.

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1		(a) The Office of the Secretary of State shall collect
2		annual user fees from any individual, partnership,
3		association, corporation, or agency of the United States
4		government that registers any combination of 10 or more of the
5		following types of motor vehicles in the Covered Area: (1)
6		vehicles of the First Division, as defined in the Illinois
7		Vehicle Code; (2) vehicles of the Second Division registered
8		under the B, C, D, F, H, MD, MF, MG, MH and MJ plate
9		categories, as defined in the Illinois Vehicle Code; and (3)
10		commuter vans and livery vehicles as defined in the Illinois
11		Vehicle Code. This Section does not apply to vehicles
12		registered under the International Registration Plan under
13		Section 3-402.1 of the Illinois Vehicle Code. The user fee
14		shall be $20 for each vehicle registered in the Covered Area
15		for each fiscal year. The Office of the Secretary of State
16		shall collect the $20 when a vehicle's registration fee is
17		paid.
18		(b) Owners of State, county, and local government
19		vehicles, rental vehicles, antique vehicles, expanded-use
20		antique vehicles, electric vehicles, and motorcycles are
21		exempt from paying the user fees on such vehicles.
22		(c) The Office of the Secretary of State shall deposit the
23		user fees collected into the Electric Vehicle and Charging
24		Rebate Fund.
25		(Source: P.A. 101-505, eff. 1-1-20; 102-662, eff. 9-15-21.)

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1		(415 ILCS 120/36 new)
2		Sec. 36. Electric vehicle and charging financial
3		assistance.
4		(a) Beginning January 1, 2029, the Agency shall administer
5		grants and other forms of financial assistance to support the
6		electrification of the transportation sector, including
7		electric passenger vehicles, electric school buses and
8		electric transit buses, electric medium-duty and heavy-duty
9		trucks, and electric vehicle charging infrastructure. The
10		Agency shall also implement customer education and outreach
11		programs that increase awareness of the programs for and the
12		benefits of transportation electrification. The programs under
13		this Section shall be developed and implemented pursuant to
14		the goals outlined in Section 45 of the Electric Vehicle Act.
15		(b) No later than March 1, 2028, and every 3 years
16		thereafter, the Agency shall publish a draft Transportation
17		Electrification Plan that specifies the proposed programs and
18		allocation of funds for the following 3 calendar years. The
19		Agency shall solicit public comments on the design of the Plan
20		and the funding allocations and shall incorporate any public
21		comments into the final Plan. The Plan shall take into
22		consideration lessons learned from the implementation of
23		utility Beneficial Electrification Plans under the Electric
24		Vehicle Act. Within 180 days after the publication of the
25		draft Plan, the Agency shall publish a final Plan.
26		(c) The Agency shall have broad authority to provide

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1		grants and other forms of financial assistance to public and
2		private entities under this Section pursuant to the Grant
3		Accountability and Transparency Act. Awardees under this
4		Section shall comply with the requirements of the Prevailing
5		Wage Act for charging station installations. The Agency may
6		provide additional incentives for projects located in eligible
7		communities.
8		(d) Funds shall be made available from the Electric
9		Vehicle and Charging Fund to the Agency pursuant to subsection
10		(c). The annual budget for Agency-administered transportation
11		electrification programs shall be equivalent to the annual
12		budget of programs administered by utilities under the
13		Electric Vehicle Act for the years 2026 through 2028.
14		(415 ILCS 120/40)
15		Sec. 40. Appropriations from the Electric Vehicle and
16		Charging Rebate Fund.
17		(a) The Agency shall estimate the amount of user fees
18		expected to be collected under Section 35 of this Act for each
19		fiscal year. User fee funds shall be deposited into and
20		distributed from the Electric Vehicle and Charging Rebate Fund
21		in the following manner:
22		(1) Through fiscal year 2023, an annual amount not to
23		exceed $225,000 may be appropriated to the Agency from the
24		Electric Vehicle and Charging Rebate Fund to pay its costs
25		of administering the programs authorized by Section 27 of

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1		this Act. Beginning in fiscal year 2024 and in each fiscal
2		year thereafter, an annual amount not to exceed $600,000
3		may be appropriated to the Agency from the Electric
4		Vehicle and Charging Rebate Fund to pay its costs of
5		administering the programs authorized by Section 27 of
6		this Act. An amount not to exceed $225,000 may be
7		appropriated to the Secretary of State from the Electric
8		Vehicle and Charging Rebate Fund to pay the Secretary of
9		State's costs of administering the programs authorized
10		under this Act.
11		(2) In fiscal year 2022 and each fiscal year
12		thereafter, after appropriation of the amounts authorized
13		by item (1) of subsection (a) of this Section, the
14		remaining moneys estimated to be collected during each
15		fiscal year shall be appropriated.
16		(3) (Blank).
17		(4) Moneys appropriated to fund the programs
18		authorized in Sections 25 and 30 shall be expended only
19		after they have been collected and deposited into the
20		Electric Vehicle and Charging Rebate Fund.
21		(b) Amounts appropriated to and deposited into the
22		Electric Vehicle and Charging Rebate Fund from the General
23		Revenue Fund, or any other fund, shall be distributed from the
24		Electric Vehicle and Charging Rebate Fund to fund the program
25		authorized in Section 27.
26		(Source: P.A. 103-8, eff. 6-7-23; 103-363, eff. 7-28-23;

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1		103-605, eff. 7-1-24; 104-6, eff. 7-1-25.)
2		(415 ILCS 120/45)
3		Sec. 45. Electric Vehicle and Charging Rebate Fund;
4		creation; deposit of user fees. A separate fund in the State
5		treasury Treasury called the Electric Vehicle and Charging
6		Rebate Fund is created, into which shall be transferred the
7		user fees as provided in Section 35, funds as provided in
8		Section 605-1075 of the Department of Commerce and Economic
9		Opportunity Law of the Civil Administrative Code of Illinois,
10		and any other revenues, deposits, State appropriations,
11		contributions, grants, gifts, bequests, legacies of money and
12		securities, or transfers as provided by law from, without
13		limitation, governmental entities, private sources,
14		foundations, trade associations, industry organizations, and
15		not-for-profit organizations.
16		(Source: P.A. 102-662, eff. 9-15-21.)
17		Section 90-55. The Illinois Nuclear Safety Preparedness
18		Act is amended by changing Sections 3, 4, 5, 8, and 9 and by
19		adding Section 6.5 as follows:
20		(420 ILCS 5/3)  (from Ch. 111 1/2, par. 4303)
21		Sec. 3. Definitions. Unless the context otherwise clearly
22		requires, as used in this Act:
23		(1) "Agency" or "IEMA-OHS" means the Illinois Emergency

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1		Management Agency and Office of Homeland Security, or its
2		successor agency.
3		(2) "Director" means the Director of the Agency.
4		(2.5) "Emergency planning zone" means a generic area
5		around a commercial nuclear facility used to assist in
6		off-site emergency planning and the development of a
7		significant response base.
8		(3) "Person" means any individual, corporation,
9		partnership, firm, association, trust, estate, public or
10		private institution, group, agency, political subdivision of
11		this State, any other state or political subdivision or agency
12		thereof, and any legal successor, representative, agent, or
13		agency of the foregoing.
14		(4) "NRC" means the United States Nuclear Regulatory
15		Commission or any agency which succeeds to its functions in
16		the licensing of nuclear power reactors or facilities for
17		storing spent nuclear fuel.
18		(5) "High-level radioactive waste" means (1) the highly
19		radioactive material resulting from the reprocessing of spent
20		nuclear fuel including liquid waste produced directly in
21		reprocessing and any solid material derived from such liquid
22		waste that contains fission products in sufficient
23		concentrations; and (2) the highly radioactive material that
24		the NRC has determined to be high-level radioactive waste
25		requiring permanent isolation.
26		(6) "Nuclear facilities" means nuclear power plants,

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1		facilities housing nuclear test and research reactors,
2		facilities for the chemical conversion of uranium, and
3		facilities for the storage of spent nuclear fuel or high-level
4		radioactive waste.
5		(7) "Spent nuclear fuel" means fuel that has been
6		withdrawn from a nuclear reactor following irradiation, the
7		constituent elements of which have not been separated by
8		reprocessing.
9		(8) "Transuranic waste" means material contaminated with
10		elements that have an atomic number greater than 92, including
11		neptunium, plutonium, americium, and curium, excluding
12		radioactive wastes shipped to a licensed low-level radioactive
13		waste disposal facility.
14		(9) "Highway route controlled quantity of radioactive
15		materials" means that quantity of radioactive materials
16		defined as a highway route controlled quantity under rules of
17		the United States Department of Transportation, or any
18		successor agency.
19		(10) "Nuclear power plant" or "nuclear steam-generating
20		facility" means a thermal power plant in which the energy
21		(heat) released by the fissioning of nuclear fuel is used to
22		boil water to produce steam.
23		(11) "Nuclear power reactor" means an apparatus, other
24		than an atomic weapon, designed or used to sustain nuclear
25		fission in a self-supporting chain reaction.
26		(12) (Blank). "Small modular reactor" or "SMR" means an

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1		advanced nuclear reactor: (1) with a rated nameplate capacity
2		of 300 electrical megawatts or less; and (2) that may be
3		constructed and operated in combination with similar reactors
4		at a single site.
5		(13) "Site boundary" means the line beyond which the land
6		or property is not owned, leased, or otherwise controlled by
7		the licensee.
8		(Source: P.A. 103-569, eff. 6-1-24.)
9		(420 ILCS 5/4)  (from Ch. 111 1/2, par. 4304)
10		Sec. 4. Nuclear accident plans; fees.
11		(a) Persons engaged within this State in the production of
12		electricity utilizing nuclear energy, the operation of nuclear
13		test and research reactors, the chemical conversion of
14		uranium, or the transportation, storage or possession of spent
15		nuclear fuel or high-level radioactive waste shall pay fees to
16		cover the cost of establishing plans and programs to deal with
17		the possibility of nuclear accidents. Except as provided
18		below, the fees shall be used to fund those Agency and local
19		government activities defined as necessary by the Director to
20		implement and maintain the plans and programs authorized by
21		this Act.
22		(b) Local governments incurring expenses attributable to
23		implementation and maintenance of the plans and programs
24		authorized by this Act may apply to the Agency for
25		compensation for those expenses, and upon approval by the

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1		Director of applications submitted by local governments, the
2		Agency shall compensate local governments from fees collected
3		under this Section. The Agency shall, by rule, determine the
4		method for compensating local governments under this Section.
5		Compensation for local governments shall include $250,000 in
6		any year through fiscal year 1993, $275,000 in fiscal year
7		1994 and fiscal year 1995, $300,000 in fiscal year 1996,
8		$400,000 in fiscal year 1997, and $450,000 in fiscal year 1998
9		and thereafter.
10		(c) Appropriations to the Agency Department of Nuclear
11		Safety (of which the Agency is the successor) for compensation
12		to local governments from the Nuclear Safety Emergency
13		Preparedness Fund provided for in this Section shall not
14		exceed $1,500,000 $650,000 per State fiscal year. Expenditures
15		from these appropriations shall not exceed, in a single State
16		fiscal year, the annual compensation amount made available to
17		local governments under this Section, unexpended funds made
18		available for local government compensation in the previous
19		fiscal year, and funds recovered under the Illinois Grant
20		Funds Recovery Act during previous fiscal years.
21		Notwithstanding any other provision of this Act, the
22		expenditure limitation for fiscal year 1998 shall include the
23		additional $100,000 made available to local governments for
24		fiscal year 1997 under this amendatory Act of 1997. The Agency
25		shall, by rule, determine the method for compensating local
26		governments under this Section. The appropriation shall not

SB0025 Enrolled - 963 - LRB104 07069 BAB 17106 b
1		exceed $500,000 in any year preceding fiscal year 1996; the
2		appropriation shall not exceed $625,000 in fiscal year 1996,
3		$725,000 in fiscal year 1997, and $775,000 in fiscal year 1998
4		and thereafter. The fees shall consist of the following:
5		(d) Persons operating commercial nuclear power reactors
6		shall pay fees as follows:
7		(1) A one-time fee for each nuclear power reactor
8		commencing operation in this State after January 1, 2026
9		charge of $590,000 per nuclear power station in this State
10		to be paid pursuant to Section 5 of this Act and according
11		to the following: by the owners of the stations.
12		(A) $1,500,000 for a reactor located at a new site
13		requiring an emergency planning zone;
14		(B) $500,000 for a reactor located on the site of a
15		reactor that commenced operation prior to January 1,
16		2026;
17		(C) $600,000 for a reactor located at a new site
18		not requiring an emergency planning zone.
19		(1.5) For nuclear power reactors in operation on
20		January 1, 2026, a one-time fee of $500,000 per nuclear
21		power reactor in this State to be paid pursuant to Section
22		5 of this Act.
23		(2) For nuclear power reactors that have a plume
24		exposure pathway emergency planning zone that extends
25		beyond the site boundary, an annual fee per nuclear power
26		reactor shall be as follows: An additional charge of

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1		$240,000 per nuclear power station for which a fee under
2		subparagraph (1) was paid before June 30, 1982.
3		(A) For the first fiscal year following the
4		effective date of this amendatory Act of the 104th
5		General Assembly, the base fee shall be $3,900,000 per
6		operating reactor.
7		(B) For each of the 9 fiscal years after the
8		effective date of this amendatory Act of the 104th
9		General Assembly, the base fee shall be increased
10		annually by 1.5% of the prior fiscal year's fee.
11		(C) The annual adjustment described in
12		subparagraph (B) of this paragraph (2) shall terminate
13		after the tenth fiscal year. Beginning with the 11th
14		fiscal year, and for each fiscal year thereafter, the
15		base fee shall remain at the amount established in the
16		tenth fiscal year and shall not be subject to further
17		automatic increases under this Section, unless and
18		until this subparagraph (C) is amended by the General
19		Assembly.
20		(D) Payment shall be made pursuant to Section 5 of
21		this Act.
22		(3) For nuclear power reactors not required to have an
23		emergency planning zone, the annual fee per nuclear
24		reactor shall be $750,000 until the NRC terminates the
25		license. Through June 30, 1982, an annual fee of $75,000
26		per year for each nuclear power reactor for which an

SB0025 Enrolled - 965 - LRB104 07069 BAB 17106 b
1		operating license has been issued by the NRC, and after
2		June 30, 1982, and through June 30, 1984 an annual fee of
3		$180,000 per year for each nuclear power reactor for which
4		an operating license has been issued by the NRC, and after
5		June 30, 1984, and through June 30, 1991, an annual fee of
6		$400,000 for each nuclear power reactor for which an
7		operating license has been issued by the NRC, to be paid by
8		the owners of nuclear power reactors operating in this
9		State. After June 30, 1991, the owners of nuclear power
10		reactors in this State for which operating licenses have
11		been issued by the NRC shall pay the following fees for
12		each such nuclear power reactor: for State fiscal year
13		1992, $925,000; for State fiscal year 1993, $975,000; for
14		State fiscal year 1994; $1,010,000; for State fiscal year
15		1995, $1,060,000; for State fiscal years 1996 and 1997,
16		$1,110,000; for State fiscal year 1998, $1,314,000; for
17		State fiscal year 1999, $1,368,000; for State fiscal year
18		2000, $1,404,000; for State fiscal year 2001, $1,696,455;
19		for State fiscal year 2002, $1,730,636; for State fiscal
20		year 2003 through State fiscal year 2011, $1,757,727; for
21		State fiscal year 2012 and subsequent fiscal years,
22		$1,903,182.
23		(3.5) The owner of a nuclear power reactor that
24		notifies the Nuclear Regulatory Commission that the
25		nuclear power reactor has permanently ceased operations
26		during State fiscal year 1998 shall pay the following fees

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1		for each such nuclear power reactor: $1,368,000 for State
2		fiscal year 1999 and $1,404,000 for State fiscal year
3		2000.
4		(4) For nuclear power reactors with an emergency
5		planning zone constructed on a new site after January 1,
6		2026, the operator or the owner shall reimburse the Agency
7		for the actual costs of any equipment, materials, and
8		labor provided for development, installation, and
9		maintenance of monitoring systems as required under
10		paragraphs (1), (2), (3), and (7) of subsection (a) of
11		Section 8 of this Act. The operator or owner shall be
12		invoiced by the Agency and payment shall be due within 60
13		days after the date of the invoice. A capital expenditure
14		surcharge of $1,400,000 per nuclear power station in this
15		State, whether operating or under construction, shall be
16		paid by the owners of the station.
17		(5) An annual fee of $25,000 per year for each site for
18		which a valid operating license has been issued by NRC for
19		the operation of an away-from-reactor spent nuclear fuel
20		or high-level radioactive waste storage facility, to be
21		paid by the owners of facilities for the storage of spent
22		nuclear fuel or high-level radioactive waste for others in
23		this State.
24		(6) A one-time charge of $280,000 for each facility in
25		this State housing a nuclear test and research reactor, to
26		be paid by the operator of the facility. However, this

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1		charge shall not be required to be paid by any
2		tax-supported institution.
3		(7) A one-time charge of $50,000 for each facility in
4		this State for the chemical conversion of uranium, to be
5		paid by the owner of the facility.
6		(8) An annual fee of $150,000 per year for each
7		facility in this State housing a nuclear test and research
8		reactor, to be paid by the operator of the facility.
9		However, this annual fee shall not be required to be paid
10		by any tax-supported institution.
11		(9) An annual fee of $15,000 per year for each
12		facility in this State for the chemical conversion of
13		uranium, to be paid by the owner of the facility.
14		(10) A fee assessed at the rate of $2,500 per truck for
15		each truck shipment and $4,500 for the first cask and
16		$3,000 for each additional cask for each rail shipment of
17		spent nuclear fuel, high-level radioactive waste,
18		transuranic waste, or a highway route controlled quantity
19		of radioactive materials received at or departing from any
20		nuclear power station or away-from-reactor spent nuclear
21		fuel, high-level radioactive waste, transuranic waste
22		storage facility, or other facility in this State to be
23		paid by the shipper of the spent nuclear fuel, high level
24		radioactive waste, transuranic waste, or highway route
25		controlled quantity of radioactive material. Truck
26		shipments of greater than 250 miles in Illinois are

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1		subject to a surcharge of $25 per mile over 250 miles for
2		each truck in the shipment.
3		(11) A fee assessed at the rate of $2,500 per truck for
4		each truck shipment and $4,500 for the first cask and
5		$3,000 for each additional cask for each rail shipment of
6		spent nuclear fuel, high-level radioactive waste,
7		transuranic waste, or a highway route controlled quantity
8		of radioactive materials traversing the State to be paid
9		by the shipper of the spent nuclear fuel, high level
10		radioactive waste, transuranic waste, or highway route
11		controlled quantity of radioactive material. Truck
12		shipments of greater than 250 miles in Illinois are
13		subject to a surcharge of $25 per mile over 250 miles for
14		each truck in the shipment. For truck shipments of less
15		than 100 miles in Illinois that consist entirely of
16		cobalt-60 or other medical isotopes or both, the $2,500
17		per truck fee shall be reduced to $1,500 for the first
18		truck and $750 for each additional truck in the same
19		shipment.
20		(12) In each of the State fiscal years 1988 through
21		1991, in addition to the annual fee provided for in
22		subparagraph (3), a fee of $400,000 for each nuclear power
23		reactor for which an operating license has been issued by
24		the NRC, to be paid by the owners of nuclear power reactors
25		operating in this State. Within 120 days after the end of
26		the State fiscal years ending June 30, 1988, June 30,

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1		1989, June 30, 1990, and June 30, 1991, the Agency shall
2		determine the expenses of the Illinois Nuclear Safety
3		Preparedness Program paid from funds appropriated for
4		those fiscal years.
5		(Source: P.A. 97-195, eff. 7-25-11; 97-732, eff. 6-30-12;
6		98-728, eff. 1-1-15.)
7		(420 ILCS 5/5)  (from Ch. 111 1/2, par. 4305)
8		Sec. 5. Nuclear power reactor or spent fuel storage
9		facility operating license fees.
10		(a) Except as otherwise provided in this Section, within
11		30 days after the beginning of each State fiscal year, each
12		person who possessed a valid operating license issued by the
13		NRC for a nuclear power reactor or a spent fuel storage
14		facility during any portion of the previous fiscal year shall
15		pay to the Agency the fees imposed by Section 4 of this Act.
16		(b) The one-time fee for new nuclear power reactors
17		facility charge assessed pursuant to subparagraph (1) of
18		subsection (d) of Section 4 of this Act shall be paid to the
19		Agency not less than 2 years prior to scheduled commencement
20		of commercial operation. The one-time fee is only applicable
21		to nuclear power reactors constructed after January 1, 2026.
22		The additional facility charge assessed pursuant to
23		subparagraph (2) of Section 4 shall be paid to the Department
24		within 90 days of June 30, 1982. Fees assessed pursuant to
25		subparagraph (3) of Section 4 for State fiscal year 1992 shall

SB0025 Enrolled - 970 - LRB104 07069 BAB 17106 b
1		be payable as follows: $400,000 due on August 1, 1991, and
2		$525,000 due on January 1, 1992. Fees assessed pursuant to
3		subparagraph (3) of Section 4 for State fiscal years 1993
4		through 2011 shall be due and payable in two equal payments on
5		July 1 and January 1 during the fiscal year in which the fee is
6		due. For State fiscal year 2012 and subsequent fiscal years,
7		fees shall be due and payable in 4 equal payments on July 1,
8		October 1, January 1, and April 1 during the fiscal year in
9		which the fee is due. Fees assessed pursuant to subparagraph
10		(4) of Section 4 shall be paid in six payments, the first, in
11		the amount of $400,000, shall be due and payable 30 days after
12		the effective date of this Amendatory Act of 1984. Subsequent
13		payments shall be in the amount of $200,000 each, and shall be
14		due and payable annually on August 1, 1985 through August 1,
15		1989, inclusive. Fees assessed under the provisions of
16		subparagraphs (6) and (7) of Section 4 of this Act shall be
17		paid on or before January 1, 1990. Fees assessed under the
18		provisions of subparagraphs (8) and (9) of Section 4 of this
19		Act shall be paid on or before January 1st of each year,
20		beginning January 1, 1990. Fees assessed under the provisions
21		of subparagraphs (10) and (11) of Section 4 of this Act shall
22		be paid to the Agency within 60 days after completion of such
23		shipments within this State. Fees assessed pursuant to
24		subparagraph (12) of Section 4 shall be paid to the Agency by
25		each person who possessed a valid operating license issued by
26		the NRC for a nuclear power reactor during any portion of the

SB0025 Enrolled - 971 - LRB104 07069 BAB 17106 b
1		previous State fiscal year as follows: the fee due in fiscal
2		year 1988 shall be paid on January 15, 1988, the fee due in
3		fiscal year 1989 shall be paid on December 1, 1988, and
4		subsequent fees shall be paid annually on December 1, 1989
5		through December 1, 1990.
6		(c) The one-time fee assessed pursuant to subparagraph
7		(1.5) of subsection (d) of Section 4 of this Act shall be paid
8		in 4 equal installments to the Agency on July 1, 2026, October
9		1, 2026, January 1, 2027, and April 1, 2027.
10		(d) The annual fee for each nuclear power reactor assessed
11		pursuant to subparagraphs (2) and (3) of subsection (d) of
12		Section 4 of this Act shall be paid in 4 equal installments to
13		the Agency on July 1, October 1, January 1, and April 1 of the
14		State fiscal year the fee is due.
15		(e) Fees assessed under the provisions of subparagraphs
16		(8) and (9) of subsection (d) of Section 4 of this Act shall be
17		paid on or before January 1 of each year.
18		(f) Fees assessed under the provisions of subparagraphs
19		(10) and (11) of subsection (d) of Section 4 of this Act shall
20		be paid to the Agency within 60 days after completion of such
21		shipments within this State.
22		(b) Fees assessed pursuant to paragraph (3.5) of Section 4
23		for State fiscal years 1999 and 2000 shall be due and payable
24		in 2 equal payments on July 1 and January 1 during the fiscal
25		year in which the fee is due. The fee due on July 1, 1998 shall
26		be payable on that date, or within 10 days after the effective

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1		date of this amendatory Act of 1998, whichever is later.
2		(g) (c) Any person who fails to pay a fee assessed under
3		Section 4 of this Act within 90 days after the fee is payable
4		is liable in a civil action for an amount not to exceed 4 times
5		the amount assessed and not paid. The action shall be brought
6		by the Attorney General at the request of the Agency. If the
7		action involves a fixed facility in Illinois, the action shall
8		be brought in the Circuit Court of the county in which the
9		facility is located. If the action does not involve a fixed
10		facility in Illinois, the action shall be brought in the
11		Circuit Court of Sangamon County.
12		(Source: P.A. 97-195, eff. 7-25-11.)
13		(420 ILCS 5/6.5 new)
14		Sec. 6.5. Rulemaking. The Agency is authorized to adopt
15		rules as appropriate to implement any provision of this Act
16		not otherwise specified.
17		(420 ILCS 5/8)  (from Ch. 111 1/2, par. 4308)
18		Sec. 8. (a) The Illinois Nuclear Safety Preparedness
19		Program shall consist of an assessment of the potential
20		nuclear accidents, their radiological consequences, and the
21		necessary protective actions required to mitigate the effects
22		of such accidents. It shall include, but not necessarily be
23		limited to:
24		(1) Development of a remote effluent monitoring system

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1		capable of reliably detecting and quantifying accidental
2		radioactive releases from nuclear power plants to the
3		environment;
4		(2) Development of an environmental monitoring program
5		for nuclear facilities other than nuclear power plants;
6		(3) Development of procedures for radiological
7		assessment and radiation exposure control for areas
8		surrounding each nuclear facility in Illinois;
9		(4) Radiological training of State and local emergency
10		response personnel in accordance with the Agency's
11		responsibilities under the program;
12		(5) Participation in the development of accident
13		scenarios and in the exercising of fixed facility nuclear
14		emergency response plans;
15		(6) Development of mitigative emergency planning
16		standards including, but not limited to, standards
17		pertaining to evacuations, re-entry into evacuated areas,
18		contaminated foodstuffs and contaminated water supplies;
19		(7) Provision of specialized response equipment
20		necessary to accomplish this task;
21		(8) Implementation of the Boiler and Pressure Vessel
22		Safety program at nuclear steam-generating facilities as
23		mandated by Section 2005-35 of the Department of Nuclear
24		Safety Law, or its successor statute;
25		(9) Development and implementation of a plan for
26		inspecting and escorting all shipments of spent nuclear

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1		fuel, high-level radioactive waste, transuranic waste, and
2		highway route controlled quantities of radioactive
3		materials in Illinois;
4		(10) Implementation of the program under the Illinois
5		Nuclear Facility Safety Act; and
6		(11) Development and implementation of a
7		radiochemistry laboratory capable of preparing
8		environmental samples, performing analyses,
9		quantification, and reporting for assessment and radiation
10		exposure control due to accidental radioactive releases
11		from nuclear power plants into the environment.
12		(b) The Agency may incorporate data collected by the
13		operator of a nuclear facility into the Agency's remote
14		monitoring system.
15		(c) The owners of each nuclear power reactor in Illinois
16		shall provide the Agency all system status signals which
17		initiate Emergency Action Level Declarations, actuate accident
18		mitigation and provide mitigation verification as directed by
19		the Agency. The Agency shall designate by rule those system
20		status signals that must be provided. Signals providing
21		indication of operating power level shall also be provided.
22		The owners of the nuclear power reactors shall, at their
23		expense, ensure that valid signals will be provided
24		continuously 24 hours a day.
25		All such signals shall be provided in a manner and at a
26		frequency specified by the Agency for incorporation into and

SB0025 Enrolled - 975 - LRB104 07069 BAB 17106 b
1		augmentation of the remote effluent monitoring system
2		specified in paragraph (1) of subsection (a) of this Section.
3		Provision shall be made for assuring that such system status
4		and power level signals shall be available to the Agency
5		during reactor operation as well as throughout accidents and
6		subsequent recovery operations.
7		For nuclear reactors with operating licenses issued by the
8		Nuclear Regulatory Commission prior to the effective date of
9		this amendatory Act, such system status and power level
10		signals shall be provided to the Department of Nuclear Safety
11		(of which the Agency is the successor) by March 1, 1985. For
12		reactors without such a license on the effective date of this
13		amendatory Act, such signals shall be provided to the
14		Department prior to commencing initial fuel load for such
15		reactor. Nuclear reactors receiving their operating license
16		after September 7, 1984 (the effective date of Public Act
17		83-1342), but before July 1, 1985, shall provide such system
18		status and power level signals to the Department of Nuclear
19		Safety (of which the Agency is the successor) by September 1,
20		1985.
21		(Source: P.A. 102-133, eff. 7-23-21; 103-154, eff. 6-30-23.)
22		(420 ILCS 5/9)  (from Ch. 111 1/2, par. 4309)
23		Sec. 9. Any equipment purchased by the Agency to be
24		installed on the premises of a nuclear facility pursuant to
25		the provisions of subsections (1), (2) and (7) of Section 8 of

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1		this Act shall be installed by the owner of such nuclear
2		facility in accordance with criteria and standards established
3		by the Director of the Agency, including criteria for
4		location, supporting utilities, and methods of installation.
5		Such installation shall be at no cost to the Agency. The owner
6		of the nuclear facility shall also, at its expense, pay for
7		modifications of its facility as requested by the Agency
8		Department to accommodate the Agency's equipment including
9		updated equipment, and to accommodate changes in the Agency's
10		criteria and standards.
11		(Source: P.A. 93-1029, eff. 8-25-04.)
12		(420 ILCS 5/2.5 rep.)
13		Section 90-60. The Illinois Nuclear Safety Preparedness
14		Act is amended by repealing Section 2.5.
15		Section 90-65. The Illinois Nuclear Facility Safety Act is
16		amended by changing Sections 3.5, 5, and 7 as follows:
17		(420 ILCS 10/3.5)
18		Sec. 3.5. Definitions. In this Act:
19		"Agency" "IEMA-OHS" means the Illinois Emergency
20		Management Agency and Office of Homeland Security, or its
21		successor agency.
22		"Director" means the Director of IEMA-OHS.
23		"Nuclear facilities" means nuclear power plants,

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1		facilities housing nuclear test and research reactors,
2		facilities for the chemical conversion of uranium, and
3		facilities for the storage of spent nuclear fuel or high-level
4		radioactive waste.
5		"Nuclear power plant" or "nuclear steam-generating
6		facility" means a thermal power plant in which the energy
7		(heat) released by the fissioning of nuclear fuel is used to
8		boil water to produce steam.
9		"Nuclear power reactor" means an apparatus, other than an
10		atomic weapon, designed or used to sustain nuclear fission in
11		a self-supporting chain reaction.
12		"Small modular reactor" or "SMR" means an advanced nuclear
13		reactor: (1) with a rated nameplate capacity of 300 electrical
14		megawatts or less; and (2) that may be constructed and
15		operated in combination with similar reactors at a single
16		site.
17		(Source: P.A. 103-569, eff. 6-1-24.)
18		(420 ILCS 10/5)  (from Ch. 111 1/2, par. 4355)
19		Sec. 5. Program for Illinois nuclear power plant
20		inspectors.
21		(a) Consistent with federal law and policy statements of
22		and cooperative agreements with the Nuclear Regulatory
23		Commission with respect to State participation in health and
24		safety regulation of nuclear facilities, and in recognition of
25		the role provided for the states by such laws, policy

SB0025 Enrolled - 978 - LRB104 07069 BAB 17106 b
1		statements and cooperative agreements, the Agency shall
2		develop and implement a program for Illinois resident
3		inspectors that, when fully implemented, shall provide for one
4		full-time Agency Illinois resident inspector for at each
5		nuclear power plant in Illinois. The owner of each of the
6		nuclear power plants to which they are assigned shall provide,
7		at its expense, office space and equipment reasonably required
8		by the resident inspectors while they are on the premises of
9		the nuclear power plants. The Illinois resident inspectors
10		shall operate in accordance with a cooperative agreement
11		executed by the Agency and the Nuclear Regulatory Commission
12		and shall have access to the nuclear power plants to which they
13		have been assigned in accordance with that agreement;
14		provided, however, that the Illinois resident inspectors shall
15		have no greater access than is afforded to an a resident
16		inspector of the Nuclear Regulatory Commission.
17		(b) The Agency may also inspect licensed nuclear power
18		plants that have permanently ceased operations. The
19		inspections shall be performed by inspectors qualified as
20		Illinois resident inspectors. The inspectors need not be
21		resident at nuclear power plants that have permanently ceased
22		operations. The inspectors shall conduct inspections in
23		accordance with a cooperative agreement executed by the Agency
24		and the Nuclear Regulatory Commission and shall have access to
25		the nuclear power plants that have permanently ceased
26		operations; provided, however, that the Illinois inspectors

SB0025 Enrolled - 979 - LRB104 07069 BAB 17106 b
1		shall have no greater access than is afforded to inspectors of
2		the Nuclear Regulatory Commission. The owner of each of the
3		nuclear power plants that has permanently ceased operations
4		shall provide, at its expense, office space and equipment
5		reasonably required by the inspectors while they are on the
6		premises of the nuclear power plants.
7		(c) The Illinois resident inspectors and inspectors
8		assigned under subsection (b) shall each operate in accordance
9		with the security plan for the nuclear power plant to which
10		they are assigned, but in no event shall they be required to
11		meet any requirements imposed by a nuclear power plant owner
12		that are not imposed on resident inspectors and inspectors of
13		the Nuclear Regulatory Commission. The Agency programs and
14		activities under this Section shall not be inconsistent with
15		federal law.
16		(Source: P.A. 95-777, eff. 8-4-08.)
17		(420 ILCS 10/7)  (from Ch. 111 1/2, par. 4357)
18		Sec. 7. The Agency shall not engage in any program of
19		Illinois resident inspectors or inspectors assigned under
20		subsection (b) of Section 5 at any nuclear power plant in
21		Illinois except as specifically directed by law.
22		(Source: P.A. 95-777, eff. 8-4-08.)
23		Section 90-70. The Illinois Low-Level Radioactive Waste
24		Management Act is amended by changing Sections 3, 13, 14, 15,

SB0025 Enrolled - 980 - LRB104 07069 BAB 17106 b
1		17, and 21 as follows:
2		(420 ILCS 20/3)  (from Ch. 111 1/2, par. 241-3)
3		Sec. 3. Definitions. As used in this Act:
4		"Agency" or "IEMA-OHS" means the Illinois Emergency
5		Management Agency and Office of Homeland Security, or its
6		successor agency.
7		"Broker" means any person who takes possession of
8		low-level waste for purposes of consolidation and shipment.
9		"Compact" means the Central Midwest Interstate Low-Level
10		Radioactive Waste Compact.
11		"Decommissioning" means the measures taken at the end of a
12		facility's operating life to assure the continued protection
13		of the public from any residual radioactivity or other
14		potential hazards present at a facility.
15		"Director" means the Director of the Agency.
16		"Disposal" means the isolation of waste from the biosphere
17		in a permanent facility designed for that purpose.
18		"Facility" means a parcel of land or site, together with
19		structures, equipment and improvements on or appurtenant to
20		the land or site, which is used or is being developed for the
21		treatment, storage or disposal of low-level radioactive waste.
22		"Facility" does not include lands, sites, structures, or
23		equipment used by a generator in the generation of low-level
24		radioactive wastes.
25		"Generator" means any person who produces or possesses

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1		low-level radioactive waste in the course of or incident to
2		manufacturing, power generation, processing, medical diagnosis
3		and treatment, research, education, or other activity.
4		"Hazardous waste" means a waste, or combination of wastes,
5		which because of its quantity, concentration, or physical,
6		chemical, or infectious characteristics may cause or
7		significantly contribute to an increase in mortality or an
8		increase in serious, irreversible, or incapacitating
9		reversible, illness; or pose a substantial present or
10		potential hazard to human health or the environment when
11		improperly treated, stored, transported, or disposed of, or
12		otherwise managed, and which has been identified, by
13		characteristics or listing, as hazardous under Section 3001 of
14		the Resource Conservation and Recovery Act of 1976, P.L.
15		94-580 or under regulations of the Pollution Control Board.
16		"High-level radioactive waste" means:
17		(1) the highly radioactive material resulting from the
18		reprocessing of spent nuclear fuel including liquid waste
19		produced directly in reprocessing and any solid material
20		derived from the liquid waste that contains fission
21		products in sufficient concentrations; and
22		(2) the highly radioactive material that the Nuclear
23		Regulatory Commission has determined, on the effective
24		date of this Amendatory Act of 1988, to be high-level
25		radioactive waste requiring permanent isolation.
26		"Low-level radioactive waste" or "waste" means radioactive

SB0025 Enrolled - 982 - LRB104 07069 BAB 17106 b
1		waste not classified as (1) high-level radioactive waste, (2)
2		transuranic waste, (3) spent nuclear fuel, or (4) byproduct
3		material as defined in Sections 11e(2), 11e(3), and 11e(4) of
4		the Atomic Energy Act of 1954 (42 U.S.C. 2014). This
5		definition shall apply notwithstanding any declaration by the
6		federal government, a state, or any regulatory agency that any
7		radioactive material is exempt from any regulatory control.
8		"Mixed waste" means waste that is both "hazardous waste"
9		and "low-level radioactive waste" as defined in this Act.
10		"Nuclear facilities" means nuclear power plants,
11		facilities housing nuclear test and research reactors,
12		facilities for the chemical conversion of uranium, and
13		facilities for the storage of spent nuclear fuel or high-level
14		radioactive waste.
15		"Nuclear power plant" or "nuclear steam-generating
16		facility" means a thermal power plant in which the energy
17		(heat) released by the fissioning of nuclear fuel is used to
18		boil water to produce steam.
19		"Nuclear power reactor" means an apparatus, other than an
20		atomic weapon, designed or used to sustain nuclear fission in
21		a self-supporting chain reaction.
22		"Person" means an individual, corporation, business
23		enterprise, or other legal entity either public or private and
24		any legal successor, representative, agent, or agency of that
25		individual, corporation, business enterprise, or legal entity.
26		"Post-closure care" means the continued monitoring of the

SB0025 Enrolled - 983 - LRB104 07069 BAB 17106 b
1		regional disposal facility after closure for the purposes of
2		detecting a need for maintenance, ensuring environmental
3		safety, and determining compliance with applicable licensure
4		and regulatory requirements, and includes undertaking any
5		remedial actions necessary to protect public health and the
6		environment from radioactive releases from the facility.
7		"Regional disposal facility" or "disposal facility" means
8		the facility established by the State of Illinois under this
9		Act for disposal away from the point of generation of waste
10		generated in the region of the Compact.
11		"Release" means any spilling, leaking, pumping, pouring,
12		emitting, emptying, discharging, injecting, escaping,
13		leaching, dumping, or disposing into the environment of
14		low-level radioactive waste.
15		"Remedial action" means those actions taken in the event
16		of a release or threatened release of low-level radioactive
17		waste into the environment, to prevent or minimize the release
18		of the waste so that it does not migrate to cause substantial
19		danger to present or future public health or welfare or the
20		environment. The term includes, but is not limited to, actions
21		at the location of the release such as storage, confinement,
22		perimeter protection using dikes, trenches or ditches, clay
23		cover, neutralization, cleanup of released low-level
24		radioactive wastes, recycling or reuse, dredging or
25		excavations, repair or replacement of leaking containers,
26		collection of leachate and runoff, onsite treatment or

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1		incineration, provision of alternative water supplies, and any
2		monitoring reasonably required to assure that these actions
3		protect human health and the environment.
4		"Scientific Surveys" means, collectively, the Illinois
5		State Geological Survey and the Illinois State Water Survey of
6		the University of Illinois.
7		"Shallow land burial" means a land disposal facility in
8		which radioactive waste is disposed of in or within the upper
9		30 meters of the earth's surface. However, this definition
10		shall not include an enclosed, engineered, structurally
11		re-enforced and solidified bunker that extends below the
12		earth's surface.
13		"Small modular reactor" or "SMR" means an advanced nuclear
14		reactor: (1) with a rated nameplate capacity of 300 electrical
15		megawatts or less; and (2) that may be constructed and
16		operated in combination with similar reactors at a single
17		site.
18		"Storage" means the temporary holding of waste for
19		treatment or disposal for a period determined by Agency
20		regulations.
21		"Treatment" means any method, technique, or process,
22		including storage for radioactive decay, designed to change
23		the physical, chemical, or biological characteristics or
24		composition of any waste in order to render the waste safer for
25		transport, storage, or disposal, amenable to recovery,
26		convertible to another usable material, or reduced in volume.

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1		"Waste management" means the storage, transportation,
2		treatment, or disposal of waste.
3		(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24;
4		revised 7-30-24.)
5		(420 ILCS 20/13)  (from Ch. 111 1/2, par. 241-13)
6		Sec. 13. Waste fees.
7		(a) The Agency shall collect a fee from each generator of
8		low-level radioactive wastes in this State, except for units
9		of local government as otherwise provided in this subsection.
10		Except as provided in subsection (b) subdivision (b)(2) and
11		subsections (c) and (d), the amount of the fee shall be $100
12		$50.00 or the following amount, whichever is greater:
13		(1) $1 per cubic foot of waste shipped for storage,
14		treatment or disposal if storage of the waste for shipment
15		occurred prior to September 7, 1984;
16		(2) $2 per cubic foot of waste stored for shipment if
17		storage of the waste occurs on or after September 7, 1984,
18		but prior to October 1, 1985;
19		(1) (3) $3 per cubic foot of waste stored for shipment
20		if storage of the waste occurs on or after October 1, 1985;
21		and
22		(4) $2 per cubic foot of waste shipped for storage,
23		treatment or disposal if storage of the waste for shipment
24		occurs on or after September 7, 1984 but prior to October
25		1, 1985, provided that no fee has been collected

SB0025 Enrolled - 986 - LRB104 07069 BAB 17106 b
1		previously for storage of the waste;
2		(2) (5) $3 per cubic foot of waste shipped for
3		storage, treatment, or disposal if storage of the waste
4		for shipment occurs on or after October 1, 1985, provided
5		that no fees have been collected previously for storage of
6		the waste.
7		All fees collected under this subsection Such fees shall
8		be collected annually or as determined by the Agency and shall
9		be deposited into in the fund low-level radioactive waste
10		funds as provided in Section 14 of this Act. Notwithstanding
11		any other provision of this Act, no fee under this Section
12		shall be collected from a generator for waste generated
13		incident to manufacturing before December 31, 1980, and
14		shipped for disposal outside of this State before December 31,
15		1992, as part of a site reclamation leading to license
16		termination.
17		Units of local government are exempt from the fee
18		provisions of this subsection.
19		(b) The owner of any nuclear power reactor that has a
20		license issued by the Nuclear Regulatory Commission for any
21		portion of a State fiscal year shall pay an annual fee in
22		accordance with subsection (a) or $30,000 per nuclear power
23		reactor, whichever is less. The fee shall be paid by July 1 of
24		each State fiscal year. All moneys collected under this
25		subsection shall be deposited pursuant to Section 14 and
26		expended, subject to appropriation, for the purposes provided

SB0025 Enrolled - 987 - LRB104 07069 BAB 17106 b
1		in Section 14. (1) Small modular reactors shall pay low-level
2		radioactive waste fees in accordance with subsection (a).
3		(2) Each nuclear power reactor in this State for which an
4		operating license has been issued by the Nuclear Regulatory
5		Commission shall not be subject to the fee required by
6		subsection (a) with respect to (1) waste stored for shipment
7		if storage of the waste occurs on or after January 1, 1986; and
8		(2) waste shipped for storage, treatment or disposal if
9		storage of the waste for shipment occurs on or after January 1,
10		1986. In lieu of the fee, each reactor shall be required to pay
11		an annual fee as provided in this subsection for the
12		treatment, storage and disposal of low-level radioactive
13		waste. Beginning with State fiscal year 1986 and through State
14		fiscal year 1997, fees shall be due and payable on January 1st
15		of each year. For State fiscal year 1998 and all subsequent
16		State fiscal years, fees shall be due and payable on July 1 of
17		each fiscal year. The fee due on July 1, 1997 shall be payable
18		on that date, or within 10 days after the effective date of
19		this amendatory Act of 1997, whichever is later.
20		The owner of any nuclear power reactor that has an
21		operating license issued by the Nuclear Regulatory Commission
22		for any portion of State fiscal year 1998 shall continue to pay
23		an annual fee of $90,000 for the treatment, storage, and
24		disposal of low-level radioactive waste through State fiscal
25		year 2002. The fee shall be due and payable on July 1 of each
26		fiscal year. The fee due on July 1, 1998 shall be payable on

SB0025 Enrolled - 988 - LRB104 07069 BAB 17106 b
1		that date, or within 10 days after the effective date of this
2		amendatory Act of 1998, whichever is later. If the balance in
3		the Low-Level Radioactive Waste Facility Operation Fund
4		Low-Level Radioactive Waste Facility Development and Operation
5		Fund falls below $500,000, at as of the end of any fiscal year
6		after fiscal year 2002, the Agency is authorized to assess by
7		rule, after notice and a hearing, an additional annual fee to
8		be paid by the owners of nuclear power reactors for which
9		operating licenses have been issued by the Nuclear Regulatory
10		Commission, except that no additional annual fee shall be
11		assessed because of the fund balance at the end of fiscal year
12		2005 or the end of fiscal year 2006. The additional annual fee
13		shall be payable on the date or dates specified by rule and
14		shall not exceed $30,000 per nuclear power operating reactor
15		per year.
16		(c) (Blank). In each of State fiscal years 1988, 1989 and
17		1990, in addition to the fee imposed in subsections (b) and
18		(d), the owner of each nuclear power reactor in this State for
19		which an operating license has been issued by the Nuclear
20		Regulatory Commission shall pay a fee of $408,000. If an
21		operating license is issued during one of those 3 fiscal
22		years, the owner shall pay a prorated amount of the fee equal
23		to $1,117.80 multiplied by the number of days in the fiscal
24		year during which the nuclear power reactor was licensed.
25		The fee shall be due and payable as follows: in fiscal year
26		1988, $204,000 shall be paid on October 1, 1987 and $102,000

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1		shall be paid on each of January 1, 1988 and April 1, 1988; in
2		fiscal year 1989, $102,000 shall be paid on each of July 1,
3		1988, October 1, 1988, January 1, 1989 and April 1, 1989; and
4		in fiscal year 1990, $102,000 shall be paid on each of July 1,
5		1989, October 1, 1989, January 1, 1990 and April 1, 1990. If
6		the operating license is issued during one of the 3 fiscal
7		years, the owner shall be subject to those payment dates, and
8		their corresponding amounts, on which the owner possesses an
9		operating license and, on June 30 of the fiscal year of
10		issuance of the license, whatever amount of the prorated fee
11		remains outstanding.
12		All of the amounts collected by the Agency under this
13		subsection (c) shall be deposited into the Low-Level
14		Radioactive Waste Facility Development and Operation Fund
15		created under subsection (a) of Section 14 of this Act and
16		expended, subject to appropriation, for the purposes provided
17		in that subsection.
18		(d) (Blank). In addition to the fees imposed in
19		subsections (b) and (c), the owners of nuclear power reactors
20		in this State for which operating licenses have been issued by
21		the Nuclear Regulatory Commission shall pay the following fees
22		for each such nuclear power reactor: for State fiscal year
23		1989, $325,000 payable on October 1, 1988, $162,500 payable on
24		January 1, 1989, and $162,500 payable on April 1, 1989; for
25		State fiscal year 1990, $162,500 payable on July 1, $300,000
26		payable on October 1, $300,000 payable on January 1 and

SB0025 Enrolled - 990 - LRB104 07069 BAB 17106 b
1		$300,000 payable on April 1; for State fiscal year 1991,
2		either (1) $150,000 payable on July 1, $650,000 payable on
3		September 1, $675,000 payable on January 1, and $275,000
4		payable on April 1, or (2) $150,000 on July 1, $130,000 on the
5		first day of each month from August through December, $225,000
6		on the first day of each month from January through March and
7		$92,000 on the first day of each month from April through June;
8		for State fiscal year 1992, $260,000 payable on July 1,
9		$900,000 payable on September 1, $300,000 payable on October
10		1, $150,000 payable on January 1, and $100,000 payable on
11		April 1; for State fiscal year 1993, $100,000 payable on July
12		1, $230,000 payable on August 1 or within 10 days after July
13		31, 1992, whichever is later, and $355,000 payable on October
14		1; for State fiscal year 1994, $100,000 payable on July 1,
15		$75,000 payable on October 1 and $75,000 payable on April 1;
16		for State fiscal year 1995, $100,000 payable on July 1,
17		$75,000 payable on October 1, and $75,000 payable on April 1,
18		for State fiscal year 1996, $100,000 payable on July 1,
19		$75,000 payable on October 1, and $75,000 payable on April 1.
20		The owner of any nuclear power reactor that has an operating
21		license issued by the Nuclear Regulatory Commission for any
22		portion of State fiscal year 1998 shall pay an annual fee of
23		$30,000 through State fiscal year 2003. For State fiscal year
24		2004 and subsequent fiscal years, the owner of any nuclear
25		power reactor that has an operating license issued by the
26		Nuclear Regulatory Commission shall pay an annual fee of

SB0025 Enrolled - 991 - LRB104 07069 BAB 17106 b
1		$30,000 per reactor, provided that the fee shall not apply to a
2		nuclear power reactor with regard to which the owner notified
3		the Nuclear Regulatory Commission during State fiscal year
4		1998 that the nuclear power reactor permanently ceased
5		operations. The fee shall be due and payable on July 1 of each
6		fiscal year. The fee due on July 1, 1998 shall be payable on
7		that date, or within 10 days after the effective date of this
8		amendatory Act of 1998, whichever is later. The fee due on July
9		1, 1997 shall be payable on that date or within 10 days after
10		the effective date of this amendatory Act of 1997, whichever
11		is later. If the payments under this subsection for fiscal
12		year 1993 due on January 1, 1993, or on April 1, 1993, or both,
13		were due before the effective date of this amendatory Act of
14		the 87th General Assembly, then those payments are waived and
15		need not be made.
16		All of the amounts collected by the Agency under this
17		subsection (d) shall be deposited into the Low-Level
18		Radioactive Waste Facility Development and Operation Fund
19		created pursuant to subsection (a) of Section 14 of this Act
20		and expended, subject to appropriation, for the purposes
21		provided in that subsection.
22		All payments made by licensees under this subsection (d)
23		for fiscal year 1992 that are not appropriated and obligated
24		by the Agency above $1,750,000 per reactor in fiscal year
25		1992, shall be credited to the licensees making the payments
26		to reduce the per reactor fees required under this subsection

SB0025 Enrolled - 992 - LRB104 07069 BAB 17106 b
1		(d) for fiscal year 1993.
2		(e) (Blank). The Agency shall promulgate rules and
3		regulations establishing standards for the collection of the
4		fees authorized by this Section. The regulations shall
5		include, but need not be limited to:
6		(1) the records necessary to identify the amounts of
7		low-level radioactive wastes produced;
8		(2) the form and submission of reports to accompany
9		the payment of fees to the Agency; and
10		(3) the time and manner of payment of fees to the
11		Agency, which payments shall not be more frequent than
12		quarterly.
13		(f) Any operating agreement entered into under subsection
14		(b) of Section 5 of this Act between the Agency and any
15		disposal facility contractor shall, subject to the provisions
16		of this Act, authorize the contractor to impose upon and
17		collect from persons using the disposal facility fees designed
18		and set at levels reasonably calculated to produce sufficient
19		revenues (1) to pay all costs and expenses properly incurred
20		or accrued in connection with, and properly allocated to,
21		performance of the contractor's obligations under the
22		operating agreement, and (2) to provide reasonable and
23		appropriate compensation or profit to the contractor under the
24		operating agreement. For purposes of this subsection (f), the
25		term "costs and expenses" may include, without limitation, (i)
26		direct and indirect costs and expenses for labor, services,

SB0025 Enrolled - 993 - LRB104 07069 BAB 17106 b
1		equipment, materials, insurance and other risk management
2		costs, interest and other financing charges, and taxes or fees
3		in lieu of taxes; (ii) payments to or required by the United
4		States, the State of Illinois or any agency or department
5		thereof, the Central Midwest Interstate Low-Level Radioactive
6		Waste Compact, and subject to the provisions of this Act, any
7		unit of local government; (iii) amortization of capitalized
8		costs with respect to the disposal facility and its
9		development, including any capitalized reserves; and (iv)
10		payments with respect to reserves, accounts, escrows or trust
11		funds required by law or otherwise provided for under the
12		operating agreement.
13		(g) (Blank).
14		(h) (Blank).
15		(i) (Blank).
16		(j) (Blank).
17		(j-5) Prior to commencement of facility operations, the
18		Agency shall adopt rules providing for the establishment and
19		collection of fees and charges with respect to the use of the
20		disposal facility as provided in subsection (f) of this
21		Section.
22		(k) The regional disposal facility shall be subject to ad
23		valorem real estate taxes lawfully imposed by units of local
24		government and school districts with jurisdiction over the
25		facility. No other local government tax, surtax, fee or other
26		charge on activities at the regional disposal facility shall

SB0025 Enrolled - 994 - LRB104 07069 BAB 17106 b
1		be allowed except as authorized by the Agency.
2		(l) The Agency shall have the power, in the event that
3		acceptance of waste for disposal at the regional disposal
4		facility is suspended, delayed or interrupted, to impose
5		emergency fees on the generators of low-level radioactive
6		waste. Generators shall pay emergency fees within 30 days of
7		receipt of notice of the emergency fees. The Agency Department
8		shall deposit all of the receipts of any fees collected under
9		this subsection into the Low-Level Radioactive Waste Facility
10		Operation Fund Low-Level Radioactive Waste Facility
11		Development and Operation Fund created under subsection (b) of
12		Section 14. Emergency fees may be used to mitigate the impacts
13		of the suspension or interruption of acceptance of waste for
14		disposal. The requirements for rulemaking in the Illinois
15		Administrative Procedure Act shall not apply to the imposition
16		of emergency fees under this subsection.
17		(m) The Agency shall adopt promulgate any other rules and
18		regulations as may be necessary to implement this Section.
19		(Source: P.A. 103-569, eff. 6-1-24.)
20		(420 ILCS 20/14)  (from Ch. 111 1/2, par. 241-14)
21		Sec. 14. Waste management funds.
22		(a) There is hereby created in the State Treasury a
23		special fund to be known as the Low-Level Radioactive Waste
24		Facility Operation Fund Low-Level Radioactive Waste Facility
25		Development and Operation Fund. All monies within the

SB0025 Enrolled - 995 - LRB104 07069 BAB 17106 b
1		Low-Level Radioactive Waste Facility Operation Fund Low-Level
2		Radioactive Waste Facility Development and Operation Fund
3		shall be invested by the State Treasurer in accordance with
4		established investment practices. Interest earned by such
5		investment shall be returned to the Low-Level Radioactive
6		Waste Facility Operation Fund Low-Level Radioactive Waste
7		Facility Development and Operation Fund. The Agency shall
8		deposit all receipts from the fees required under subsections
9		(a) and (b) of Section 13 in the State Treasury to the credit
10		of this Fund. Subject to appropriation, the Agency is
11		authorized to expend all moneys in the Fund in amounts it deems
12		necessary for:
13		(1) hiring personnel and any other operating and
14		contingent expenses necessary for the proper
15		administration of this Act;
16		(2) contracting with any firm for the purpose of
17		carrying out the purposes of this Act;
18		(3) grants to the Central Midwest Interstate Low-Level
19		Radioactive Waste Commission;
20		(4) hiring personnel, contracting with any person, and
21		meeting any other expenses incurred by the Agency in
22		fulfilling its responsibilities under the Radioactive
23		Waste Compact Enforcement Act;
24		(5) activities under Sections 10, 10.2 and 10.3;
25		(6) payment of fees in lieu of taxes to a local
26		government having within its boundaries a regional

SB0025 Enrolled - 996 - LRB104 07069 BAB 17106 b
1		disposal facility;
2		(7) payment of grants to counties or municipalities
3		under Section 12.1; and
4		(8) fulfillment of obligations under a community
5		agreement under Section 12.1;
6		(9) decommissioning and other procedures required for
7		the proper closure of a regional disposal facility;
8		(10) monitoring, inspecting, and other procedures
9		required for the proper closure, decommissioning, and
10		post-closure care of a regional disposal facility;
11		(11) taking any remedial actions necessary to protect
12		human health and the environment from releases or
13		threatened releases of wastes from a regional disposal
14		facility;
15		(12) the purchase of facility and third-party
16		liability insurance necessary during the institutional
17		control period of a regional disposal facility;
18		(13) mitigating the impacts of the suspension or
19		interruption of the acceptance of waste for disposal; and
20		(14) compensating any person suffering any damages or
21		losses to a person or property caused by a release from the
22		regional disposal facility as provided for in Section 15.
23		In spending monies pursuant to such appropriations, the
24		Agency shall to the extent practicable avoid duplicating
25		expenditures made by any firm pursuant to a contract awarded
26		under this Section.

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1		(b) There is hereby created in the State Treasury a
2		special fund to be known as the Low-Level Radioactive Waste
3		Facility Closure, Post-Closure Care and Compensation Fund. All
4		monies within the Low-Level Radioactive Waste Facility
5		Closure, Post-Closure Care and Compensation Fund shall be
6		invested by the State Treasurer in accordance with established
7		investment practices. Interest earned by such investment shall
8		be returned to the Low-Level Radioactive Waste Facility
9		Closure, Post-Closure Care and Compensation Fund. All deposits
10		into this Fund shall be held by the State Treasurer separate
11		and apart from all public money or funds of this State. Subject
12		to appropriation, the Agency is authorized to expend any
13		moneys in this Fund in amounts it deems necessary for:
14		(1) decommissioning and other procedures required for
15		the proper closure of the regional disposal facility;
16		(2) monitoring, inspecting, and other procedures
17		required for the proper closure, decommissioning, and
18		post-closure care of the regional disposal facility;
19		(3) taking any remedial actions necessary to protect
20		human health and the environment from releases or
21		threatened releases of wastes from the regional disposal
22		facility;
23		(4) the purchase of facility and third-party liability
24		insurance necessary during the institutional control
25		period of the regional disposal facility;
26		(5) mitigating the impacts of the suspension or

SB0025 Enrolled - 998 - LRB104 07069 BAB 17106 b
1		interruption of the acceptance of waste for disposal;
2		(6) compensating any person suffering any damages or
3		losses to a person or property caused by a release from the
4		regional disposal facility as provided for in Section 15;
5		and
6		(7) fulfillment of obligations under a community
7		agreement under Section 12.1.
8		On or before March 1 of each year through March 1, 2025,
9		the Agency shall deliver to the Governor, the President and
10		Minority Leader of the Senate, the Speaker and Minority Leader
11		of the House, and each of the generators that have contributed
12		during the preceding State fiscal year to the Fund a financial
13		statement, certified and verified by the Director, which
14		details all receipts and expenditures from the Fund during the
15		preceding State fiscal year. The financial statements shall
16		identify all sources of income to the Fund and all recipients
17		of expenditures from the Fund, shall specify the amounts of
18		all the income and expenditures, and shall indicate the
19		amounts of all the income and expenditures, and shall indicate
20		the purpose for all expenditures.
21		On July 1, 2025, or as soon thereafter as practical, the
22		State Comptroller shall direct and the State Treasurer shall
23		transfer the remaining balance from the Low-Level Radioactive
24		Waste Facility Closure, Post-Closure Care and Compensation
25		Fund into the Low-Level Radioactive Waste Facility Operation
26		Fund Low-Level Radioactive Waste Facility Development and

SB0025 Enrolled - 999 - LRB104 07069 BAB 17106 b
1		Operation Fund. Upon completion of the transfer, the Low-Level
2		Radioactive Waste Facility Closure, Post-Closure Care and
3		Compensation Fund is dissolved, and any future deposits due to
4		that Fund and any outstanding obligations or liabilities of
5		that Fund shall pass to the Low-Level Radioactive Waste
6		Facility Development and Operation Fund.
7		(c) (Blank).
8		(d) The Agency may accept for any of its purposes and
9		functions any donations, grants of money, equipment, supplies,
10		materials, and services from any state or the United States,
11		or from any institution, person, firm or corporation. Any
12		donation or grant of money shall be deposited into the
13		Low-Level Radioactive Waste Facility Operation Fund Low-Level
14		Radioactive Waste Facility Development and Operation Fund.
15		(Source: P.A. 104-2, eff. 6-16-25.)
16		(420 ILCS 20/15)  (from Ch. 111 1/2, par. 241-15)
17		Sec. 15. Compensation.
18		(a) Any person may apply to the Agency pursuant to this
19		Section for compensation of a loss caused by the release, in
20		Illinois, of radioactivity from the regional disposal
21		facility. The Agency shall prescribe appropriate forms and
22		procedures for claims filed pursuant to this Section, which
23		shall include, as a minimum, the following:
24		(1) Provisions requiring the claimant to make a sworn
25		verification of the claim to the best of his or her

SB0025 Enrolled - 1000 - LRB104 07069 BAB 17106 b
1		knowledge.
2		(2) A full description, supported by appropriate
3		evidence from government agencies, of the release of the
4		radioactivity claimed to be the cause of the physical
5		injury, illness, loss of income or property damage.
6		(3) If making a claim based upon physical injury or
7		illness, certification of the medical history of the
8		claimant for the 5 years preceding the date of the claim,
9		along with certification of the alleged physical injury or
10		illness, and expenses for the physical injury or illness,
11		made by hospitals, physicians or other qualified medical
12		authorities.
13		(4) If making a claim for lost income, information on
14		the claimant's income as reported on his or her federal
15		income tax return or other document for the preceding 3
16		years in order to compute lost wages or income.
17		(b) The Agency shall hold at least one hearing, if
18		requested by the claimant, within 60 days of submission of a
19		claim to the Agency. The Director shall render a decision on a
20		claim within 30 days of the hearing unless all of the parties
21		to the claim agree in writing to an extension of time. All
22		decisions rendered by the Director shall be in writing, with
23		notification to all appropriate parties. The decision shall be
24		considered a final administrative decision for the purposes of
25		judicial review.
26		(c) The following losses shall be compensable under this

SB0025 Enrolled - 1001 - LRB104 07069 BAB 17106 b
1		Section, provided that the Agency has found that the claimant
2		has established, by the weight of the evidence, that the
3		losses were proximately caused by the designated release and
4		are not otherwise compensable under law:
5		(1) One hundred percent of uninsured, out-of-pocket
6		medical expenses, for up to 3 years from the onset of
7		treatment;
8		(2) Eighty percent of any uninsured, actual lost
9		wages, or business income in lieu of wages, caused by
10		injury to the claimant or the claimant's property, not to
11		exceed $15,000 per year for 3 years;
12		(3) Eighty percent of any losses or damages to real or
13		personal property; and
14		(4) One hundred percent of costs of any remedial
15		actions on such property necessary to protect human health
16		and the environment.
17		(d) No claim may be presented to the Agency under this
18		Section later than 5 years from the date of discovery of the
19		damage or loss.
20		(e) Compensation for any damage or loss under this Section
21		shall preclude indemnification or reimbursement from any other
22		source for the identical damage or loss, and indemnification
23		or reimbursement from any other source shall preclude
24		compensation under this Section.
25		(f) The Agency shall adopt, and revise when appropriate,
26		rules and regulations necessary to implement the provisions of

SB0025 Enrolled - 1002 - LRB104 07069 BAB 17106 b
1		this Section, including methods that provide for establishing
2		that a claimant has exercised reasonable diligence in
3		satisfying the conditions of the application requirements, for
4		specifying the proof necessary to establish a damage or loss
5		compensable under this Section and for establishing the
6		administrative procedures to be followed in reviewing claims.
7		(g) Claims approved by the Director shall be paid from the
8		Low-Level Radioactive Waste Facility Operation Fund Low-Level
9		Radioactive Waste Facility Development and Operation Fund,
10		except that claims shall not be paid in excess of the amount
11		available in the Fund. In the case of insufficient amounts in
12		the Fund to satisfy claims against the Fund, the General
13		Assembly may appropriate monies to the Fund in amounts it
14		deems necessary to pay the claims.
15		(Source: P.A. 104-2, eff. 6-16-25.)
16		(420 ILCS 20/17)  (from Ch. 111 1/2, par. 241-17)
17		Sec. 17. Penalties.
18		(a) Any person operating any facility in violation of
19		Section 8 shall be subject to a civil penalty not to exceed
20		$100,000 per day of violation.
21		(b) Any person failing to pay the fees provided for in
22		Section 13 shall be liable to a civil penalty not to exceed 4
23		times the amount of the fees not paid.
24		(c) At the request of the Agency, the civil penalties
25		shall be recovered in an action brought by the Attorney

SB0025 Enrolled - 1003 - LRB104 07069 BAB 17106 b
1		General on behalf of the State in the circuit court in which
2		the violation occurred. All amounts collected from fines under
3		this Section shall be deposited into the Low-Level Radioactive
4		Waste Facility Operation Fund Low-Level Radioactive Waste
5		Facility Development and Operation Fund.
6		(Source: P.A. 104-2, eff. 6-16-25.)
7		(420 ILCS 20/21)  (from Ch. 111 1/2, par. 241-21)
8		Sec. 21. Shared Liability. Any state which enacts the
9		Central Midwest Interstate Low-Level Radioactive Waste Compact
10		and has as its resident a generator shall be liable for the
11		cost of post-closure care in excess of funds available from
12		the Low-Level Radioactive Waste Facility Operation Fund
13		Low-Level Radioactive Waste Facility Development and Operation
14		Fund or from any liability insurance or other means of
15		establishing financial responsibility in an amount sufficient
16		to provide for any necessary corrective actions or liabilities
17		arising during the period of post-closure care. The extent of
18		such liability shall not be in excess of the prorated share of
19		the volume of waste placed in the facility by the generators of
20		each state which has enacted the Central Midwest Interstate
21		Low-Level Radioactive Waste Compact. However, this Section
22		shall not apply to a party state with a total volume of waste
23		recorded on low-level radioactive waste manifests for any year
24		that is less than 10 percent of the total volume recorded on
25		such manifests for the region during the same year.

SB0025 Enrolled - 1004 - LRB104 07069 BAB 17106 b
1		(Source: P.A. 104-2, eff. 6-16-25.)
2		Section 90-75. The Radioactive Waste Storage Act is
3		amended by changing Sections 0.05 and 1 as follows:
4		(420 ILCS 35/0.05)
5		Sec. 0.05. Definitions. In this Act:
6		"IEMA-OHS" means the Illinois Emergency Management Agency
7		and Office of Homeland Security, or its successor agency.
8		"Director" means the Director of IEMA-OHS.
9		"Nuclear power plant" or "nuclear steam-generating
10		facility" means a thermal power plant in which the energy
11		(heat) released by the fissioning of nuclear fuel is used to
12		boil water to produce steam.
13		"Nuclear facilities" means nuclear power plants,
14		facilities housing nuclear test and research reactors,
15		facilities for the chemical conversion of uranium, and
16		facilities for the storage of spent nuclear fuel or high-level
17		radioactive waste.
18		"Nuclear power reactor" means an apparatus, other than an
19		atomic weapon, designed or used to sustain nuclear fission in
20		a self-supporting chain reaction.
21		"Small modular reactor" or "SMR" means an advanced nuclear
22		reactor: (1) with a rated nameplate capacity of 300 electrical
23		megawatts or less; and (2) that may be constructed and
24		operated in combination with similar reactors at a single

SB0025 Enrolled - 1005 - LRB104 07069 BAB 17106 b
1		site.
2		(Source: P.A. 103-569, eff. 6-1-24.)
3		(420 ILCS 35/1)  (from Ch. 111 1/2, par. 230.1)
4		Sec. 1. The Director is authorized to acquire by private
5		purchase, acceptance, or by condemnation in the manner
6		provided for the exercise of the power of eminent domain under
7		the Eminent Domain Act, any and all lands, buildings and
8		grounds where radioactive by-products and wastes produced by
9		industrial, medical, agricultural, scientific or other
10		organizations can be concentrated, stored or otherwise
11		disposed in a manner consistent with the public health and
12		safety. Whenever, in the judgment of the Director, it is
13		necessary to relocate existing facilities for the
14		construction, operation, closure or long-term care of a
15		facility for the safe and secure disposal of low-level
16		radioactive waste, the cost of relocating such existing
17		facilities may be deemed a part of the disposal facility land
18		acquisition and the Agency may, on behalf of the State, pay
19		such costs. Existing facilities include public utilities,
20		commercial or industrial facilities, residential buildings,
21		and such other public or privately owned buildings as the
22		Director deems necessary for relocation. The Agency is
23		authorized to operate a relocation program, and to pay such
24		costs of relocation as are provided in the federal "Uniform
25		Relocation Assistance and Real Property Acquisition Policies

SB0025 Enrolled - 1006 - LRB104 07069 BAB 17106 b
1		Act", Public Law 91-646. The Director is authorized to exceed
2		the maximum payments provided pursuant to the federal "Uniform
3		Relocation Assistance and Real Property Acquisition Policies
4		Act" if necessary to assure the provision of decent, safe, and
5		sanitary housing, or to secure a suitable alternate location.
6		Payments issued under this Section shall be made from the
7		Low-level Radioactive Waste Facility Development and Operation
8		Fund established by the Illinois Low-Level Radioactive Waste
9		Management Act.
10		(Source: P.A. 103-569, eff. 6-1-24.)
11		Section 90-80. The Radioactive Waste Tracking and
12		Permitting Act is amended by changing Sections 10 and 15 as
13		follows:
14		(420 ILCS 37/10)
15		Sec. 10. Definitions. As used in this Act:
16		(a) "Agency" or "IEMA-OHS" means the Illinois Emergency
17		Management Agency and Office of Homeland Security, or its
18		successor agency.
19		(b) "Director" means the Director of the Agency.
20		(c) "Disposal" means the isolation of waste from the
21		biosphere in a permanent facility designed for that purpose.
22		(d) "Facility" means a parcel of land or a site, together
23		with structures, equipment, and improvements on or appurtenant
24		to the land or site, that is used or is being developed for the

SB0025 Enrolled - 1007 - LRB104 07069 BAB 17106 b
1		treatment, storage, or disposal of low-level radioactive
2		waste.
3		(e) "Low-level radioactive waste" or "waste" means
4		radioactive waste not classified as (1) high-level radioactive
5		waste, (2) transuranic waste, (3) spent nuclear fuel, or (4)
6		byproduct material as defined in Sections 11e(2), 11e(3), and
7		11e(4) of the Atomic Energy Act (42 U.S.C. 2014). This
8		definition shall apply notwithstanding any declaration by the
9		federal government, a state, or any regulatory agency that any
10		radioactive material is exempt from any regulatory control.
11		(e-5) "Nuclear facilities" means nuclear power plants,
12		facilities housing nuclear test and research reactors,
13		facilities for the chemical conversion of uranium, and
14		facilities for the storage of spent nuclear fuel or high-level
15		radioactive waste.
16		(e-10) "Nuclear power plant" or "nuclear steam-generating
17		facility" means a thermal power plant in which the energy
18		(heat) released by the fissioning of nuclear fuel is used to
19		boil water to produce steam.
20		(e-15) "Nuclear power reactor" means an apparatus, other
21		than an atomic weapon, designed or used to sustain nuclear
22		fission in a self-supporting chain reaction.
23		(e-20) (Blank). "Small modular reactor" or "SMR" means an
24		advanced nuclear reactor: (1) with a rated nameplate capacity
25		of 300 electrical megawatts or less; and (2) that may be
26		constructed and operated in combination with similar reactors

SB0025 Enrolled - 1008 - LRB104 07069 BAB 17106 b
1		at a single site.
2		(f) "Person" means an individual, corporation, business
3		enterprise, or other legal entity, public or private, or any
4		legal successor, representative, agent, or agency of that
5		individual, corporation, business enterprise, or legal entity.
6		(g) "Regional facility" or "disposal facility" means a
7		facility that is located in Illinois and established by
8		Illinois, under designation of Illinois as a host state by the
9		Commission for disposal of waste.
10		(h) "Storage" means the temporary holding of waste for
11		treatment or disposal for a period determined by Agency
12		regulations.
13		(i) "Treatment" means any method, technique, or process,
14		including storage for radioactive decay, that is designed to
15		change the physical, chemical, or biological characteristics
16		or composition of any waste in order to render the waste safer
17		for transport, storage, or disposal, amenable to recovery,
18		convertible to another usable material, or reduced in volume.
19		(Source: P.A. 103-306, eff. 7-28-23; 103-569, eff. 6-1-24;
20		revised 7-31-24.)
21		(420 ILCS 37/15)
22		Sec. 15. Permit requirements for the storage, treatment,
23		and disposal of waste at a disposal facility.
24		(a) Upon adoption of regulations under subsection (c) of
25		this Section, no person shall deposit any low-level

SB0025 Enrolled - 1009 - LRB104 07069 BAB 17106 b
1		radioactive waste at a storage, treatment, or disposal
2		facility in Illinois licensed under Section 8 of the Illinois
3		Low-Level Radioactive Waste Management Act without a permit
4		granted by the Agency.
5		(b) Upon adoption of regulations under subsection (c) of
6		this Section, no person shall operate a storage, treatment, or
7		disposal facility licensed under Section 8 of the Illinois
8		Low-Level Radioactive Waste Management Act without a permit
9		granted by the Agency.
10		(c) The Agency shall adopt regulations providing for the
11		issuance, suspension, and revocation of permits required under
12		subsections (a) and (b) of this Section. The regulations may
13		provide a system for tracking low-level radioactive waste to
14		ensure that waste that other states are responsible for
15		disposing of under federal law does not become the
16		responsibility of the State of Illinois. The regulations shall
17		be consistent with the Federal Hazardous Materials
18		Transportation Act.
19		(d) The Agency may enter into a contract or contracts for
20		operation of the system for tracking low-level radioactive
21		waste as provided in subsection (c) of this Section.
22		(e) A person who violates this Section or any regulation
23		promulgated under this Section shall be subject to a civil
24		penalty, not to exceed $10,000, for each violation. Each day a
25		violation continues shall constitute a separate offense. A
26		person who fails to pay a civil penalty imposed by a regulation

SB0025 Enrolled - 1010 - LRB104 07069 BAB 17106 b
1		adopted under this Section, or any portion of the penalty, is
2		liable in a civil action in an amount not to exceed 4 times the
3		amount imposed and not paid. At the request of the Agency, the
4		Attorney General shall, on behalf of the State, bring an
5		action for the recovery of any civil penalty provided for by
6		this Section. Any civil penalties so recovered shall be
7		deposited into the Low-Level Radioactive Waste Facility
8		Operation Fund Low-Level Radioactive Waste Facility
9		Development and Operation.
10		(Source: P.A. 103-569, eff. 6-1-24; 104-2, eff. 6-16-25.)
11		Section 90-85. The Radiation Protection Act of 1990 is
12		amended by changing Section 4 as follows:
13		(420 ILCS 40/4)  (from Ch. 111 1/2, par. 210-4)
14		(Section scheduled to be repealed on January 1, 2027)
15		Sec. 4. Definitions. As used in this Act:
16		(a) "Accreditation" means the process by which the Agency
17		grants permission to persons meeting the requirements of this
18		Act and the Agency's rules and regulations to engage in the
19		practice of administering radiation to human beings.
20		(a-2) "Agency" or "IEMA-OHS" means the Illinois Emergency
21		Management Agency and Office of Homeland Security, or its
22		successor agency.
23		(a-3) "Assistant Director" means the Assistant Director of
24		the Agency.

SB0025 Enrolled - 1011 - LRB104 07069 BAB 17106 b
1		(a-5) "By-product material" means: (1) any radioactive
2		material (except special nuclear material) yielded in or made
3		radioactive by exposure to radiation incident to the process
4		of producing or utilizing special nuclear material; (2) the
5		tailings or wastes produced by the extraction or concentration
6		of uranium or thorium from any ore processed primarily for its
7		source material content, including discrete surface wastes
8		resulting from underground solution extraction processes but
9		not including underground ore bodies depleted by such solution
10		extraction processes; (3) any discrete source of radium-226
11		that is produced, extracted, or converted after extraction,
12		before, on, or after August 8, 2005, for use for a commercial,
13		medical, or research activity; (4) any material that has been
14		made radioactive by use of a particle accelerator and is
15		produced, extracted, or converted after extraction before, on,
16		or after August 8, 2005, for use for a commercial, medical, or
17		research activity; and (5) any discrete source of naturally
18		occurring radioactive material, other than source material,
19		that is extracted or converted after extraction for use in
20		commercial, medical, or research activity before, on, or after
21		August 8, 2005, and which the U.S. Nuclear Regulatory
22		Commission, in consultation with the Administrator of the
23		Environmental Protection Agency, the Secretary of Energy, the
24		Secretary of Homeland Security, and the head of any other
25		appropriate Federal agency, determines would pose a threat to
26		the public health and safety or the common defense and

SB0025 Enrolled - 1012 - LRB104 07069 BAB 17106 b
1		security similar to the threat posed by a discrete source or
2		radium-226.
3		(b) (Blank).
4		(c) (Blank).
5		(d) "General license" means a license, pursuant to
6		regulations promulgated by the Agency, effective without the
7		filing of an application to transfer, acquire, own, possess or
8		use quantities of, or devices or equipment utilizing,
9		radioactive material, including but not limited to by-product,
10		source or special nuclear materials.
11		(d-1) "Identical in substance" means the regulations
12		promulgated by the Agency would require the same actions with
13		respect to ionizing radiation, for the same group of affected
14		persons, as would federal laws, regulations, or orders if any
15		federal agency, including but not limited to the Nuclear
16		Regulatory Commission, Food and Drug Administration, or
17		Environmental Protection Agency, administered the subject
18		program in Illinois.
19		(d-3) "Mammography" means radiography of the breast
20		primarily for the purpose of enabling a physician to determine
21		the presence, size, location and extent of cancerous or
22		potentially cancerous tissue in the breast.
23		(d-5) "Nuclear facilities" means nuclear power plants,
24		facilities housing nuclear test and research reactors,
25		facilities for the chemical conversion of uranium, and
26		facilities for the storage of spent nuclear fuel or high-level

SB0025 Enrolled - 1013 - LRB104 07069 BAB 17106 b
1		radioactive waste.
2		(d-5.5) "Nuclear power plant" or "nuclear steam-generating
3		facility" means a thermal power plant in which the energy
4		(heat) released by the fissioning of nuclear fuel is used to
5		boil water to produce steam.
6		(d-5.10) "Nuclear power reactor" means an apparatus, other
7		than an atomic weapon, designed or used to sustain nuclear
8		fission in a self-supporting chain reaction.
9		(d-7) "Operator" is an individual, group of individuals,
10		partnership, firm, corporation, association, or other entity
11		conducting the business or activities carried on within a
12		radiation installation.
13		(e) "Person" means any individual, corporation,
14		partnership, firm, association, trust, estate, public or
15		private institution, group, agency, political subdivision of
16		this State, any other State or political subdivision or agency
17		thereof, and any legal successor, representative, agent, or
18		agency of the foregoing, other than the United States Nuclear
19		Regulatory Commission, or any successor thereto, and other
20		than federal government agencies licensed by the United States
21		Nuclear Regulatory Commission, or any successor thereto.
22		"Person" also includes a federal entity (and its contractors)
23		if the federal entity agrees to be regulated by the State or as
24		otherwise allowed under federal law.
25		(f) "Radiation" or "ionizing radiation" means gamma rays
26		and x-rays, alpha and beta particles, high speed electrons,

SB0025 Enrolled - 1014 - LRB104 07069 BAB 17106 b
1		neutrons, protons, and other nuclear particles or
2		electromagnetic radiations capable of producing ions directly
3		or indirectly in their passage through matter; but does not
4		include sound or radio waves or visible, infrared, or
5		ultraviolet light.
6		(f-5) "Radiation emergency" means the uncontrolled release
7		of radioactive material from a radiation installation which
8		poses a potential threat to the public health, welfare, and
9		safety.
10		(g) "Radiation installation" is any location or facility
11		where radiation machines are used or where radioactive
12		material is produced, transported, stored, disposed of, or
13		used for any purpose.
14		(h) "Radiation machine" is any device that produces
15		radiation when in use.
16		(i) "Radioactive material" means any solid, liquid, or
17		gaseous substance which emits radiation spontaneously.
18		(j) "Radiation source" or "source of ionizing radiation"
19		means a radiation machine or radioactive material as defined
20		herein.
21		(j-5) (Blank). "Small modular reactor" or "SMR" means an
22		advanced nuclear reactor: (1) with a rated nameplate capacity
23		of 300 electrical megawatts or less; and (2) that may be
24		constructed and operated in combination with similar reactors
25		at a single site.
26		(k) "Source material" means (1) uranium, thorium, or any

SB0025 Enrolled - 1015 - LRB104 07069 BAB 17106 b
1		other material which the Agency declares by order to be source
2		material after the United States Nuclear Regulatory
3		Commission, or any successor thereto, has determined the
4		material to be such; or (2) ores containing one or more of the
5		foregoing materials, in such concentration as the Agency
6		declares by order to be source material after the United
7		States Nuclear Regulatory Commission, or any successor
8		thereto, has determined the material in such concentration to
9		be source material.
10		(l) "Special nuclear material" means (1) plutonium,
11		uranium 233, uranium enriched in the isotope 233 or in the
12		isotope 235, and any other material which the Agency declares
13		by order to be special nuclear material after the United
14		States Nuclear Regulatory Commission, or any successor
15		thereto, has determined the material to be such, but does not
16		include source material; or (2) any material artificially
17		enriched by any of the foregoing, but does not include source
18		material.
19		(m) "Specific license" means a license, issued after
20		application, to use, manufacture, produce, transfer, receive,
21		acquire, own, or possess quantities of, or devices or
22		equipment utilizing radioactive materials.
23		(Source: P.A. 103-569, eff. 6-1-24.)
24		Section 90-90. The Uranium and Thorium Mill Tailings
25		Control Act is amended by changing Section 10 as follows:

SB0025 Enrolled - 1016 - LRB104 07069 BAB 17106 b
1		(420 ILCS 42/10)
2		Sec. 10. Definitions. As used in this Act:
3		"Agency" or "IEMA-OHS" means the Illinois Emergency
4		Management Agency and Office of Homeland Security, or its
5		successor agency.
6		"By-product material" means the tailings or wastes
7		produced by the extraction or concentration of uranium or
8		thorium from any ore processed primarily for its source
9		material content, including discrete surface wastes resulting
10		from underground solution extraction processes but not
11		including underground ore bodies depleted by such solution
12		extraction processes.
13		"Director" means the Director of the Agency.
14		"Nuclear facilities" means nuclear power plants,
15		facilities housing nuclear test and research reactors,
16		facilities for the chemical conversion of uranium, and
17		facilities for the storage of spent nuclear fuel or high-level
18		radioactive waste.
19		"Nuclear power plant" or "nuclear steam-generating
20		facility" means a thermal power plant in which the energy
21		(heat) released by the fissioning of nuclear fuel is used to
22		boil water to produce steam.
23		"Nuclear power reactor" means an apparatus, other than an
24		atomic weapon, designed or used to sustain nuclear fission in
25		a self-supporting chain reaction.

SB0025 Enrolled - 1017 - LRB104 07069 BAB 17106 b
1		"Person" means any individual, corporation, partnership,
2		firm, association, trust, estate, public or private
3		institution, group, agency, political subdivision of this
4		State, any other State or political subdivision or agency
5		thereof, and any legal successor, representative, agent, or
6		agency of the foregoing, other than the United States Nuclear
7		Regulatory Commission, or any successor thereto, and other
8		than federal government agencies licensed by the United States
9		Nuclear Regulatory Commission, or any successor thereto.
10		"Radiation emergency" means the uncontrolled release of
11		radioactive material from a radiation installation that poses
12		a potential threat to the public health, welfare, and safety.
13		"Small modular reactor" or "SMR" means an advanced nuclear
14		reactor: (1) with a rated nameplate capacity of 300 electrical
15		megawatts or less; and (2) that may be constructed and
16		operated in combination with similar reactors at a single
17		site.
18		"Source material" means (i) uranium, thorium, or any other
19		material that the Agency declares by order to be source
20		material after the United States Nuclear Regulatory Commission
21		or its successor has determined the material to be source
22		material; or (ii) ores containing one or more of those
23		materials in such concentration as the Agency declares by
24		order to be source material after the United States Nuclear
25		Regulatory Commission or its successor has determined the
26		material in such concentration to be source material.

SB0025 Enrolled - 1018 - LRB104 07069 BAB 17106 b
1		"Specific license" means a license, issued after
2		application, to use, manufacture, produce, transfer, receive,
3		acquire, own, or possess quantities of radioactive materials
4		or devices or equipment utilizing radioactive materials.
5		(Source: P.A. 103-569, eff. 6-1-24.)
6		Section 90-95. The Laser System Act of 1997 is amended by
7		changing Section 15 as follows:
8		(420 ILCS 56/15)
9		Sec. 15. Definitions. For the purposes of this Act, unless
10		the context requires otherwise:
11		"Agency" or "IEMA-OHS" means the Illinois Emergency
12		Management Agency and Office of Homeland Security, or its
13		successor agency.
14		"Director" means the Director of the Agency.
15		"FDA" means the Food and Drug Administration of the United
16		States Department of Health and Human Services.
17		"Laser installation" means a location or facility where
18		laser systems are produced, stored, disposed of, or used for
19		any purpose. "Laser installation" does not include any private
20		residence.
21		"Laser installation operator" means an individual, group
22		of individuals, partnership, firm, corporation, association,
23		or other entity conducting any business or activity within a
24		laser installation.

SB0025 Enrolled - 1019 - LRB104 07069 BAB 17106 b
1		"Laser machine" means a device that is capable of
2		producing or projecting laser radiation when associated
3		controlled devices are operated.
4		"Laser radiation" means an electromagnetic radiation
5		emitted from a laser system and includes all reflected
6		radiation, any secondary radiation, or other forms of energy
7		resulting from the primary laser beam.
8		"Laser safety officer" means an individual who is
9		qualified by training and experience in the evaluation and
10		control of laser hazards, as evidenced by satisfaction of the
11		training and experience requirements adopted by the Agency
12		under subsection (b) of Section 16, and who is designated,
13		where required by Sections 16 and 17, by a laser installation
14		operator or temporary laser display operator to have the
15		authority and responsibility to establish and administer a
16		laser radiation protection program for a particular laser
17		installation or temporary laser display.
18		"Laser system" means a device, laser projector, laser
19		machine, equipment, or other apparatus that applies a source
20		of energy to a gas, liquid, crystal, or other solid substances
21		or combination thereof in a manner that electromagnetic
22		radiations of a relatively uniform wave length are amplified
23		and emitted in a cohesive beam capable of transmitting the
24		energy developed in a manner that may be harmful to living
25		tissues, including, but not limited to, electromagnetic waves
26		in the range of visible, infrared, or ultraviolet light. Such

SB0025 Enrolled - 1020 - LRB104 07069 BAB 17106 b
1		systems in schools, colleges, occupational schools, and State
2		colleges and other State institutions are also included in the
3		definition of "laser systems". "Laser system" includes laser
4		machines but does not include any device, machine, equipment,
5		or other apparatus used in the provision of communications
6		through fiber optic cable.
7		"Nuclear facilities" means nuclear power plants,
8		facilities housing nuclear test and research reactors,
9		facilities for the chemical conversion of uranium, and
10		facilities for the storage of spent nuclear fuel or high-level
11		radioactive waste.
12		"Nuclear power plant" or "nuclear steam-generating
13		facility" means a thermal power plant in which the energy
14		(heat) released by the fissioning of nuclear fuel is used to
15		boil water to produce steam.
16		"Nuclear power reactor" means an apparatus, other than an
17		atomic weapon, designed or used to sustain nuclear fission in
18		a self-supporting chain reaction.
19		"Small modular reactor" or "SMR" means an advanced nuclear
20		reactor: (1) with a rated nameplate capacity of 300 electrical
21		megawatts or less; and (2) that may be constructed and
22		operated in combination with similar reactors at a single
23		site.
24		"Temporary laser display" means a visual effect display
25		created for a limited period of time at a laser installation by
26		a laser system that is not a permanent fixture in the laser

SB0025 Enrolled - 1021 - LRB104 07069 BAB 17106 b
1		installation for the entertainment of the public or invitees,
2		regardless of whether admission is charged or whether the
3		laser display takes place indoors or outdoors.
4		"Temporary laser display operator" means an individual,
5		group of individuals, partnership, firm, corporation,
6		association, or other entity conducting a temporary laser
7		display at a laser installation.
8		(Source: P.A. 102-558, eff. 8-20-21; 103-277, eff. 7-28-23;
9		103-569, eff. 6-1-24.)
10		ARTICLE 99.
11		Section 99-97. Severability. The provisions of this Act
12		are severable under Section 1.31 of the Statute on Statutes.