Bill Text: IL HB5856 | 2023-2024 | 103rd General Assembly | Introduced


Bill Title: Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to (i) conduct competitive solicitations to procure contracted energy storage credits sufficient to achieve certain energy storage standards, and (ii) request, review, and accept proposals, execute contracts, and procure energy storage credits. Requires the Agency to develop a storage procurement plan. Authorizes the Agency to develop and implement a firm energy resource procurement plan. Makes other changes. Amends the Public Utilities Act. Requires each electric utility to demonstrate sufficient resources devoted to interconnection. Requires the Illinois Commerce Commission to perform specified actions regarding interconnection within 90 days after the effective date of the amendatory Act. In a provision regarding virtual power plant programs, requires each electric utility serving more than 300,000 customers as of January 1, 2023 to propose an initial tariff within 60 days after the effective date of the amendatory Act. In a provision regarding peak remediation programs, requires each electric utility serving more than 300,000 retail customers as of January 1, 2023 to propose an initial tariff within 90 days after the effective date of the amendatory Act. Requires the Commission to establish a working group with relevant stakeholders to develop a stand-alone energy storage distribution deployment program. Provides that, beginning on June 1, 2024, the electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of energy storage credits to meet specified energy storage standards. Requires the Agency to prepare an energy storage resources procurement plan for the procurement of energy storage credits. Requires the Commission to establish an Office of Interconnection and Renewable Development, which shall (i) actively seek input from all interested parties and shall develop a thorough understanding and critical analyses of the tools and techniques used to promote development and remove barriers to development of the projects and devices, and (ii) monitor interconnection between electric utilities and applicants for interconnection and interconnection customers. Sets forth reporting requirements for the Office. Makes other changes. Effective immediately.

Spectrum: Partisan Bill (Democrat 1-0)

Status: (Introduced) 2024-05-24 - Referred to Rules Committee [HB5856 Detail]

Download: Illinois-2023-HB5856-Introduced.html

103RD GENERAL ASSEMBLY
State of Illinois
2023 and 2024
HB5856

Introduced , by Rep. Barbara Hernandez

SYNOPSIS AS INTRODUCED:
See Index

Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to (i) conduct competitive solicitations to procure contracted energy storage credits sufficient to achieve certain energy storage standards, and (ii) request, review, and accept proposals, execute contracts, and procure energy storage credits. Requires the Agency to develop a storage procurement plan. Authorizes the Agency to develop and implement a firm energy resource procurement plan. Makes other changes. Amends the Public Utilities Act. Requires each electric utility to demonstrate sufficient resources devoted to interconnection. Requires the Illinois Commerce Commission to perform specified actions regarding interconnection within 90 days after the effective date of the amendatory Act. In a provision regarding virtual power plant programs, requires each electric utility serving more than 300,000 customers as of January 1, 2023 to propose an initial tariff within 60 days after the effective date of the amendatory Act. In a provision regarding peak remediation programs, requires each electric utility serving more than 300,000 retail customers as of January 1, 2023 to propose an initial tariff within 90 days after the effective date of the amendatory Act. Requires the Commission to establish a working group with relevant stakeholders to develop a stand-alone energy storage distribution deployment program. Provides that, beginning on June 1, 2024, the electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of energy storage credits to meet specified energy storage standards. Requires the Agency to prepare an energy storage resources procurement plan for the procurement of energy storage credits. Requires the Commission to establish an Office of Interconnection and Renewable Development, which shall (i) actively seek input from all interested parties and shall develop a thorough understanding and critical analyses of the tools and techniques used to promote development and remove barriers to development of the projects and devices, and (ii) monitor interconnection between electric utilities and applicants for interconnection and interconnection customers. Sets forth reporting requirements for the Office. Makes other changes. Effective immediately.
LRB103 40655 LNS 73376 b

A BILL FOR

HB5856LRB103 40655 LNS 73376 b
1 AN ACT concerning regulation.
2 Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
4 Section 5. The Illinois Power Agency Act is amended by
5changing Sections 1-5, 1-10, 1-20, and 1-75 and by adding
6Sections 1-93 and 1-94 as follows:
7 (20 ILCS 3855/1-5)
8 Sec. 1-5. Legislative declarations and findings. The
9General Assembly finds and declares:
10 (1) The health, welfare, and prosperity of all
11 Illinois residents require the provision of adequate,
12 reliable, affordable, efficient, and environmentally
13 sustainable electric service at the lowest total cost over
14 time, taking into account any benefits of price stability.
15 (1.5) To provide the highest quality of life for the
16 residents of Illinois and to provide for a clean and
17 healthy environment, it is the policy of this State to
18 rapidly transition to 100% clean energy by 2050.
19 (2) (Blank).
20 (3) (Blank).
21 (4) It is necessary to improve the process of
22 procuring electricity to serve Illinois residents, to
23 promote investment in energy efficiency and

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1 demand-response measures, and to maintain and support
2 development of clean coal technologies, generation
3 resources that operate at all hours of the day and under
4 all weather conditions, zero emission facilities, and
5 renewable resources.
6 (5) Procuring a diverse electricity supply portfolio
7 will ensure the lowest total cost over time for adequate,
8 reliable, efficient, and environmentally sustainable
9 electric service.
10 (6) Including renewable resources and zero emission
11 credits from zero emission facilities in that portfolio
12 will reduce long-term direct and indirect costs to
13 consumers by decreasing environmental impacts and by
14 avoiding or delaying the need for new generation,
15 transmission, and distribution infrastructure. Developing
16 new renewable energy resources in Illinois, including
17 brownfield solar projects and community solar projects,
18 will help to diversify Illinois electricity supply, avoid
19 and reduce pollution, reduce peak demand, and enhance
20 public health and well-being of Illinois residents.
21 (7) Developing community solar projects in Illinois
22 will help to expand access to renewable energy resources
23 to more Illinois residents.
24 (8) Developing brownfield solar projects in Illinois
25 will help return blighted or contaminated land to
26 productive use while enhancing public health and the

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1 well-being of Illinois residents, including those in
2 environmental justice communities.
3 (9) Energy efficiency, demand-response measures, zero
4 emission energy, and renewable energy are resources
5 currently underused in Illinois. These resources should be
6 used, when cost effective, to reduce costs to consumers,
7 improve reliability, and improve environmental quality and
8 public health.
9 (10) The State should encourage the use of advanced
10 clean coal technologies that capture and sequester carbon
11 dioxide emissions to advance environmental protection
12 goals and to demonstrate the viability of coal and
13 coal-derived fuels in a carbon-constrained economy.
14 (10.5) The State should encourage the development of
15 interregional high voltage direct current (HVDC)
16 transmission lines that benefit Illinois. All ratepayers
17 in the State served by the regional transmission
18 organization where the HVDC converter station is
19 interconnected benefit from the long-term price stability
20 and market access provided by interregional HVDC
21 transmission facilities. The benefits to Illinois include:
22 reduction in wholesale power prices; access to lower-cost
23 markets; enabling the integration of additional renewable
24 generating units within the State through near
25 instantaneous dispatchability and the provision of
26 ancillary services; creating good-paying union jobs in

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1 Illinois; and, enhancing grid reliability and climate
2 resilience via HVDC facilities that are installed
3 underground.
4 (10.6) The health, welfare, and safety of the people
5 of the State are advanced by developing new HVDC
6 transmission lines predominantly along transportation
7 rights-of-way, with an HVDC converter station that is
8 located in the service territory of a public utility as
9 defined in Section 3-105 of the Public Utilities Act
10 serving more than 3,000,000 retail customers, and with a
11 project labor agreement as defined in Section 1-10 of this
12 Act.
13 (11) The General Assembly enacted Public Act 96-0795
14 to reform the State's purchasing processes, recognizing
15 that government procurement is susceptible to abuse if
16 structural and procedural safeguards are not in place to
17 ensure independence, insulation, oversight, and
18 transparency.
19 (12) The principles that underlie the procurement
20 reform legislation apply also in the context of power
21 purchasing.
22 (13) To ensure that the benefits of installing
23 renewable resources are available to all Illinois
24 residents and located across the State, subject to
25 appropriation, it is necessary for the Agency to provide
26 public information and educational resources on how

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1 residents can benefit from the expansion of renewable
2 energy in Illinois and participate in the Illinois Solar
3 for All Program established in Section 1-56, the
4 Adjustable Block program established in Section 1-75, the
5 job training programs established by paragraph (1) of
6 subsection (a) of Section 16-108.12 of the Public
7 Utilities Act, and the programs and resources established
8 by the Energy Transition Act.
9 (14) The deployment of energy storage systems is
10 necessary to achieve high levels of renewable energy, to
11 avoid the use of peaking fossil fuel plants, and to
12 maintain an efficient, reliable, and resilient electric
13 grid.
14 The General Assembly therefore finds that it is necessary
15to create the Illinois Power Agency and that the goals and
16objectives of that Agency are to accomplish each of the
17following:
18 (A) Develop electricity procurement plans to ensure
19 adequate, reliable, affordable, efficient, and
20 environmentally sustainable electric service at the lowest
21 total cost over time, taking into account any benefits of
22 price stability, for electric utilities that on December
23 31, 2005 provided electric service to at least 100,000
24 customers in Illinois and for small multi-jurisdictional
25 electric utilities that (i) on December 31, 2005 served
26 less than 100,000 customers in Illinois and (ii) request a

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1 procurement plan for their Illinois jurisdictional load.
2 The procurement plan shall be updated on an annual basis
3 and shall include renewable energy resources and,
4 beginning with the delivery year commencing June 1, 2017,
5 zero emission credits from zero emission facilities
6 sufficient to achieve the standards specified in this Act.
7 (B) Conduct the competitive procurement processes
8 identified in this Act.
9 (C) Develop electric generation and co-generation
10 facilities that use indigenous coal or renewable
11 resources, or both, financed with bonds issued by the
12 Illinois Finance Authority.
13 (D) Supply electricity from the Agency's facilities at
14 cost to one or more of the following: municipal electric
15 systems, governmental aggregators, or rural electric
16 cooperatives in Illinois.
17 (E) Ensure that the process of power procurement is
18 conducted in an ethical and transparent fashion, immune
19 from improper influence.
20 (F) Continue to review its policies and practices to
21 determine how best to meet its mission of providing the
22 lowest cost power to the greatest number of people, at any
23 given point in time, in accordance with applicable law.
24 (G) Operate in a structurally insulated, independent,
25 and transparent fashion so that nothing impedes the
26 Agency's mission to secure power at the best prices the

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1 market will bear, provided that the Agency meets all
2 applicable legal requirements.
3 (H) Implement renewable energy procurement and
4 training programs throughout the State to diversify
5 Illinois electricity supply, improve reliability, avoid
6 and reduce pollution, reduce peak demand, and enhance
7 public health and well-being of Illinois residents,
8 including low-income residents.
9 (I) Implement procurements to cost-effectively deploy
10 contracted energy storage systems.
11(Source: P.A. 102-662, eff. 9-15-21.)
12 (20 ILCS 3855/1-10)
13 Sec. 1-10. Definitions.
14 "Agency" means the Illinois Power Agency.
15 "Agency loan agreement" means any agreement pursuant to
16which the Illinois Finance Authority agrees to loan the
17proceeds of revenue bonds issued with respect to a project to
18the Agency upon terms providing for loan repayment
19installments at least sufficient to pay when due all principal
20of, interest and premium, if any, on those revenue bonds, and
21providing for maintenance, insurance, and other matters in
22respect of the project.
23 "Authority" means the Illinois Finance Authority.
24 "Brownfield site photovoltaic project" means photovoltaics
25that are either:

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1 (1) interconnected to an electric utility as defined
2 in this Section, a municipal utility as defined in this
3 Section, a public utility as defined in Section 3-105 of
4 the Public Utilities Act, or an electric cooperative as
5 defined in Section 3-119 of the Public Utilities Act and
6 located at a site that is regulated by any of the following
7 entities under the following programs:
8 (A) the United States Environmental Protection
9 Agency under the federal Comprehensive Environmental
10 Response, Compensation, and Liability Act of 1980, as
11 amended;
12 (B) the United States Environmental Protection
13 Agency under the Corrective Action Program of the
14 federal Resource Conservation and Recovery Act, as
15 amended;
16 (C) the Illinois Environmental Protection Agency
17 under the Illinois Site Remediation Program; or
18 (D) the Illinois Environmental Protection Agency
19 under the Illinois Solid Waste Program; or
20 (2) located at the site of a coal mine that has
21 permanently ceased coal production, permanently halted any
22 re-mining operations, and is no longer accepting any coal
23 combustion residues; has both completed all clean-up and
24 remediation obligations under the federal Surface Mining
25 and Reclamation Act of 1977 and all applicable Illinois
26 rules and any other clean-up, remediation, or ongoing

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1 monitoring to safeguard the health and well-being of the
2 people of the State of Illinois, as well as demonstrated
3 compliance with all applicable federal and State
4 environmental rules and regulations, including, but not
5 limited, to 35 Ill. Adm. Code Part 845 and any rules for
6 historic fill of coal combustion residuals, including any
7 rules finalized in Subdocket A of Illinois Pollution
8 Control Board docket R2020-019.
9 "Clean coal facility" means an electric generating
10facility that uses primarily coal as a feedstock and that
11captures and sequesters carbon dioxide emissions at the
12following levels: at least 50% of the total carbon dioxide
13emissions that the facility would otherwise emit if, at the
14time construction commences, the facility is scheduled to
15commence operation before 2016, at least 70% of the total
16carbon dioxide emissions that the facility would otherwise
17emit if, at the time construction commences, the facility is
18scheduled to commence operation during 2016 or 2017, and at
19least 90% of the total carbon dioxide emissions that the
20facility would otherwise emit if, at the time construction
21commences, the facility is scheduled to commence operation
22after 2017. The power block of the clean coal facility shall
23not exceed allowable emission rates for sulfur dioxide,
24nitrogen oxides, carbon monoxide, particulates and mercury for
25a natural gas-fired combined-cycle facility the same size as
26and in the same location as the clean coal facility at the time

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1the clean coal facility obtains an approved air permit. All
2coal used by a clean coal facility shall have high volatile
3bituminous rank and greater than 1.7 pounds of sulfur per
4million Btu content, unless the clean coal facility does not
5use gasification technology and was operating as a
6conventional coal-fired electric generating facility on June
71, 2009 (the effective date of Public Act 95-1027).
8 "Clean coal SNG brownfield facility" means a facility that
9(1) has commenced construction by July 1, 2015 on an urban
10brownfield site in a municipality with at least 1,000,000
11residents; (2) uses a gasification process to produce
12substitute natural gas; (3) uses coal as at least 50% of the
13total feedstock over the term of any sourcing agreement with a
14utility and the remainder of the feedstock may be either
15petroleum coke or coal, with all such coal having a high
16bituminous rank and greater than 1.7 pounds of sulfur per
17million Btu content unless the facility reasonably determines
18that it is necessary to use additional petroleum coke to
19deliver additional consumer savings, in which case the
20facility shall use coal for at least 35% of the total feedstock
21over the term of any sourcing agreement; and (4) captures and
22sequesters at least 85% of the total carbon dioxide emissions
23that the facility would otherwise emit.
24 "Clean coal SNG facility" means a facility that uses a
25gasification process to produce substitute natural gas, that
26sequesters at least 90% of the total carbon dioxide emissions

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1that the facility would otherwise emit, that uses at least 90%
2coal as a feedstock, with all such coal having a high
3bituminous rank and greater than 1.7 pounds of sulfur per
4million Btu content, and that has a valid and effective permit
5to construct emission sources and air pollution control
6equipment and approval with respect to the federal regulations
7for Prevention of Significant Deterioration of Air Quality
8(PSD) for the plant pursuant to the federal Clean Air Act;
9provided, however, a clean coal SNG brownfield facility shall
10not be a clean coal SNG facility.
11 "Clean energy" means energy generation that is 90% or
12greater free of carbon dioxide emissions.
13 "Commission" means the Illinois Commerce Commission.
14 "Community renewable generation project" means an electric
15generating facility that:
16 (1) is powered by wind, solar thermal energy,
17 photovoltaic cells or panels, biodiesel, crops and
18 untreated and unadulterated organic waste biomass, and
19 hydropower that does not involve new construction of dams;
20 (2) is interconnected at the distribution system level
21 of an electric utility as defined in this Section, a
22 municipal utility as defined in this Section that owns or
23 operates electric distribution facilities, a public
24 utility as defined in Section 3-105 of the Public
25 Utilities Act, or an electric cooperative, as defined in
26 Section 3-119 of the Public Utilities Act;

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1 (3) credits the value of electricity generated by the
2 facility to the subscribers of the facility; and
3 (4) is limited in nameplate capacity to less than or
4 equal to 5,000 kilowatts.
5 "Costs incurred in connection with the development and
6construction of a facility" means:
7 (1) the cost of acquisition of all real property,
8 fixtures, and improvements in connection therewith and
9 equipment, personal property, and other property, rights,
10 and easements acquired that are deemed necessary for the
11 operation and maintenance of the facility;
12 (2) financing costs with respect to bonds, notes, and
13 other evidences of indebtedness of the Agency;
14 (3) all origination, commitment, utilization,
15 facility, placement, underwriting, syndication, credit
16 enhancement, and rating agency fees;
17 (4) engineering, design, procurement, consulting,
18 legal, accounting, title insurance, survey, appraisal,
19 escrow, trustee, collateral agency, interest rate hedging,
20 interest rate swap, capitalized interest, contingency, as
21 required by lenders, and other financing costs, and other
22 expenses for professional services; and
23 (5) the costs of plans, specifications, site study and
24 investigation, installation, surveys, other Agency costs
25 and estimates of costs, and other expenses necessary or
26 incidental to determining the feasibility of any project,

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1 together with such other expenses as may be necessary or
2 incidental to the financing, insuring, acquisition, and
3 construction of a specific project and starting up,
4 commissioning, and placing that project in operation.
5 "Daily energy volatility index" means a calculation, for a
6contracted energy storage system, of the difference in average
7price per megawatt hour between the average of the "X" highest
8priced hours and the "X" lowest priced hours for each day,
9adjusted for energy storage round trip efficiency, in the
10day-ahead energy market of the energy storage duration of the
11contracted energy storage system for each day in the day-ahead
12energy market of the applicable pricing node of the
13independent system operator or regional transmission
14organization, where "X" equals the energy storage duration of
15the contracted energy storage system.
16 "Delivery services" has the same definition as found in
17Section 16-102 of the Public Utilities Act.
18 "Delivery year" means the consecutive 12-month period
19beginning June 1 of a given year and ending May 31 of the
20following year.
21 "Department" means the Department of Commerce and Economic
22Opportunity.
23 "Director" means the Director of the Illinois Power
24Agency.
25 "Demand-response" means measures that decrease peak
26electricity demand or shift demand from peak to off-peak

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1periods.
2 "Distributed renewable energy generation device" means a
3device that is:
4 (1) powered by wind, solar thermal energy,
5 photovoltaic cells or panels, biodiesel, crops and
6 untreated and unadulterated organic waste biomass, tree
7 waste, and hydropower that does not involve new
8 construction of dams, waste heat to power systems, or
9 qualified combined heat and power systems;
10 (2) interconnected at the distribution system level of
11 either an electric utility as defined in this Section, a
12 municipal utility as defined in this Section that owns or
13 operates electric distribution facilities, or a rural
14 electric cooperative as defined in Section 3-119 of the
15 Public Utilities Act;
16 (3) located on the customer side of the customer's
17 electric meter and is primarily used to offset that
18 customer's electricity load; and
19 (4) (blank).
20 "Energy efficiency" means measures that reduce the amount
21of electricity or natural gas consumed in order to achieve a
22given end use. "Energy efficiency" includes voltage
23optimization measures that optimize the voltage at points on
24the electric distribution voltage system and thereby reduce
25electricity consumption by electric customers' end use
26devices. "Energy efficiency" also includes measures that

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1reduce the total Btus of electricity, natural gas, and other
2fuels needed to meet the end use or uses.
3 "Energy storage capacity" means the nameplate capacity of
4a contracted energy storage system, measured in megawatts AC.
5 "Energy storage credit" means a fungible credit that
6represents the flexibility value of a contracted energy
7storage system. An energy storage credit is produced for each
8one megawatt of energy storage capacity multiplied by the
9energy storage duration each day that the contracted energy
10storage system is interconnected with wholesale electricity
11markets.
12 "Energy storage credit counterparty" has the same meaning
13as "public utility" as defined in Section 3-105 of the Public
14Utilities Act.
15 "Energy storage credit value" means a price, measured in
16dollars per credit, calculated for each day for a contracted
17energy storage system by subtracting the daily energy
18volatility index and the reference capacity price from the
19energy storage strike price.
20 "Energy storage duration" means the number of hours over
21which an energy storage system is capable of continuously
22discharging energy at its full energy storage capacity.
23 "Energy storage round-trip efficiency" means the ratio of
24energy discharged from an energy storage system at its energy
25capacity divided by the energy used to charge the energy
26storage system at its energy capacity.

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1 "Energy storage strike price" means a contract price for
2energy storage credits from a contracted energy storage
3system.
4 "Energy storage system" means commercially available
5technology that is capable of absorbing energy and storing it
6for use at a later time, including, but not limited to,
7electrochemical and electromechanical technologies. "Energy
8storage system" does not include technologies that require
9combustion.
10 "Electric utility" has the same definition as found in
11Section 16-102 of the Public Utilities Act.
12 "Equity investment eligible community" or "eligible
13community" are synonymous and mean the geographic areas
14throughout Illinois which would most benefit from equitable
15investments by the State designed to combat discrimination.
16Specifically, the eligible communities shall be defined as the
17following areas:
18 (1) R3 Areas as established pursuant to Section 10-40
19 of the Cannabis Regulation and Tax Act, where residents
20 have historically been excluded from economic
21 opportunities, including opportunities in the energy
22 sector; and
23 (2) environmental justice communities, as defined by
24 the Illinois Power Agency pursuant to the Illinois Power
25 Agency Act, where residents have historically been subject
26 to disproportionate burdens of pollution, including

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1 pollution from the energy sector.
2 "Equity eligible persons" or "eligible persons" means
3persons who would most benefit from equitable investments by
4the State designed to combat discrimination, specifically:
5 (1) persons who graduate from or are current or former
6 participants in the Clean Jobs Workforce Network Program,
7 the Clean Energy Contractor Incubator Program, the
8 Illinois Climate Works Preapprenticeship Program,
9 Returning Residents Clean Jobs Training Program, or the
10 Clean Energy Primes Contractor Accelerator Program, and
11 the solar training pipeline and multi-cultural jobs
12 program created in paragraphs (a)(1) and (a)(3) of Section
13 16-208.12 of the Public Utilities Act;
14 (2) persons who are graduates of or currently enrolled
15 in the foster care system;
16 (3) persons who were formerly incarcerated;
17 (4) persons whose primary residence is in an equity
18 investment eligible community.
19 "Equity eligible contractor" means a business that is
20majority-owned by eligible persons, or a nonprofit or
21cooperative that is majority-governed by eligible persons, or
22is a natural person that is an eligible person offering
23personal services as an independent contractor.
24 "Facility" means an electric generating unit or a
25co-generating unit that produces electricity along with
26related equipment necessary to connect the facility to an

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1electric transmission or distribution system.
2 "General contractor" means the entity or organization with
3main responsibility for the building of a construction project
4and who is the party signing the prime construction contract
5for the project.
6 "Governmental aggregator" means one or more units of local
7government that individually or collectively procure
8electricity to serve residential retail electrical loads
9located within its or their jurisdiction.
10 "High voltage direct current converter station" means the
11collection of equipment that converts direct current energy
12from a high voltage direct current transmission line into
13alternating current using Voltage Source Conversion technology
14and that is interconnected with transmission or distribution
15assets located in Illinois.
16 "High voltage direct current renewable energy credit"
17means a renewable energy credit associated with a renewable
18energy resource where the renewable energy resource has
19entered into a contract to transmit the energy associated with
20such renewable energy credit over high voltage direct current
21transmission facilities.
22 "High voltage direct current transmission facilities"
23means the collection of installed equipment that converts
24alternating current energy in one location to direct current
25and transmits that direct current energy to a high voltage
26direct current converter station using Voltage Source

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1Conversion technology. "High voltage direct current
2transmission facilities" includes the high voltage direct
3current converter station itself and associated high voltage
4direct current transmission lines. Notwithstanding the
5preceding, after September 15, 2021 (the effective date of
6Public Act 102-662), an otherwise qualifying collection of
7equipment does not qualify as high voltage direct current
8transmission facilities unless its developer entered into a
9project labor agreement, is capable of transmitting
10electricity at 525kv with an Illinois converter station
11located and interconnected in the region of the PJM
12Interconnection, LLC, and the system does not operate as a
13public utility, as that term is defined in Section 3-105 of the
14Public Utilities Act.
15 "Hydropower" means any method of electricity generation or
16storage that results from the flow of water, including
17impoundment facilities, diversion facilities, and pumped
18storage facilities.
19 "Index price" means the real-time energy settlement price
20at the applicable Illinois trading hub, such as PJM-NIHUB or
21MISO-IL, for a given settlement period. "Index price" may, if
22a utility-scale wind facility or a utility-scale solar
23facility interconnected with an electric utility elects to use
24an alternative definition, also include the monthly settlement
25of the applicable seasonal qualifying facilities rate offered
26by the interconnecting electric utility.

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1 "Indexed credit" means a credit subject to a contract
2described in Section 1-93.
3 "Indexed renewable energy credit" means a tradable credit
4that represents the environmental attributes of one megawatt
5hour of energy produced from a renewable energy resource, the
6price of which shall be calculated by subtracting the strike
7price offered by a new utility-scale wind project or a new
8utility-scale photovoltaic project from the index price in a
9given settlement period.
10 "Indexed renewable energy credit counterparty" has the
11same meaning as "public utility" as defined in Section 3-105
12of the Public Utilities Act.
13 "Local government" means a unit of local government as
14defined in Section 1 of Article VII of the Illinois
15Constitution.
16 "Long-duration energy storage" means an energy storage
17system capable of dispatching energy at its full rated
18capacity for 10 or more hours.
19 "Long-term energy storage contract" means a contract for
20the purchase of energy storage credits generated by an energy
21storage system for a period of at least 15 years.
22 "Modernized" or "retooled" means the construction, repair,
23maintenance, or significant expansion of turbines and existing
24hydropower dams.
25 "Multi-day energy storage" means an energy storage system
26capable of dispatching energy at its full rated capacity for

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1greater than 24 hours.
2 "Municipality" means a city, village, or incorporated
3town.
4 "Municipal utility" means a public utility owned and
5operated by any subdivision or municipal corporation of this
6State.
7 "Nameplate capacity" means the aggregate inverter
8nameplate capacity in kilowatts AC. "Nameplate capacity" does
9not include the capacity of an energy storage system
10associated with a renewable energy resource.
11 "Person" means any natural person, firm, partnership,
12corporation, either domestic or foreign, company, association,
13limited liability company, joint stock company, or association
14and includes any trustee, receiver, assignee, or personal
15representative thereof.
16 "Project" means the planning, bidding, and construction of
17a facility.
18 "Project labor agreement" means a pre-hire collective
19bargaining agreement that covers all terms and conditions of
20employment on a specific construction project and must include
21the following:
22 (1) provisions establishing the minimum hourly wage
23 for each class of labor organization employee;
24 (2) provisions establishing the benefits and other
25 compensation for each class of labor organization
26 employee;

HB5856- 22 -LRB103 40655 LNS 73376 b
1 (3) provisions establishing that no strike or disputes
2 will be engaged in by the labor organization employees;
3 (4) provisions establishing that no lockout or
4 disputes will be engaged in by the general contractor
5 building the project; and
6 (5) provisions for minorities and women, as defined
7 under the Business Enterprise for Minorities, Women, and
8 Persons with Disabilities Act, setting forth goals for
9 apprenticeship hours to be performed by minorities and
10 women and setting forth goals for total hours to be
11 performed by underrepresented minorities and women.
12 A labor organization and the general contractor building
13the project shall have the authority to include other terms
14and conditions as they deem necessary.
15 "Public utility" has the same definition as found in
16Section 3-105 of the Public Utilities Act.
17 "Qualified combined heat and power systems" means systems
18that, either simultaneously or sequentially, produce
19electricity and useful thermal energy from a single fuel
20source. Such systems are eligible for "renewable energy
21credits" in an amount equal to its total energy output where a
22renewable fuel is consumed or in an amount equal to the net
23reduction in nonrenewable fuel consumed on a total energy
24output basis.
25 "Real property" means any interest in land together with
26all structures, fixtures, and improvements thereon, including

HB5856- 23 -LRB103 40655 LNS 73376 b
1lands under water and riparian rights, any easements,
2covenants, licenses, leases, rights-of-way, uses, and other
3interests, together with any liens, judgments, mortgages, or
4other claims or security interests related to real property.
5 "Reference capacity price" means a price, measured in
6dollars per megawatt hour, representing the revenue available
7for a contracted energy storage system through participation
8in the MISO Planning Resource Auction or the PJM Base Residual
9Auction, or their successor resource adequacy constructs. The
10reference capacity price shall be calculated by adjusting the
11currently prevailing clearing price in the MISO Planning
12Resource Auction or the PJM Base Residual Action, or their
13successor resource adequacy constructs, by the accredited
14capacity of the contracted energy storage system and
15converting the units to megawatt hours.
16 "Renewable energy credit" means a tradable credit that
17represents the environmental attributes of one megawatt hour
18of energy produced from a renewable energy resource.
19 "Renewable energy resources" includes energy and its
20associated renewable energy credit or renewable energy credits
21from wind, solar thermal energy, photovoltaic cells and
22panels, biodiesel, anaerobic digestion, crops and untreated
23and unadulterated organic waste biomass, and hydropower that
24does not involve new construction of dams, waste heat to power
25systems, or qualified combined heat and power systems. For
26purposes of this Act, landfill gas produced in the State is

HB5856- 24 -LRB103 40655 LNS 73376 b
1considered a renewable energy resource. "Renewable energy
2resources" does not include the incineration or burning of
3tires, garbage, general household, institutional, and
4commercial waste, industrial lunchroom or office waste,
5landscape waste, railroad crossties, utility poles, or
6construction or demolition debris, other than untreated and
7unadulterated waste wood. "Renewable energy resources" also
8includes high voltage direct current renewable energy credits
9and the associated energy converted to alternating current by
10a high voltage direct current converter station to the extent
11that: (1) the generator of such renewable energy resource
12contracted with a third party to transmit the energy over the
13high voltage direct current transmission facilities, and (2)
14the third-party contracting for delivery of renewable energy
15resources over the high voltage direct current transmission
16facilities have ownership rights over the unretired associated
17high voltage direct current renewable energy credit.
18 "Retail customer" has the same definition as found in
19Section 16-102 of the Public Utilities Act.
20 "Revenue bond" means any bond, note, or other evidence of
21indebtedness issued by the Authority, the principal and
22interest of which is payable solely from revenues or income
23derived from any project or activity of the Agency.
24 "Sequester" means permanent storage of carbon dioxide by
25injecting it into a saline aquifer, a depleted gas reservoir,
26or an oil reservoir, directly or through an enhanced oil

HB5856- 25 -LRB103 40655 LNS 73376 b
1recovery process that may involve intermediate storage,
2regardless of whether these activities are conducted by a
3clean coal facility, a clean coal SNG facility, a clean coal
4SNG brownfield facility, or a party with which a clean coal
5facility, clean coal SNG facility, or clean coal SNG
6brownfield facility has contracted for such purposes.
7 "Service area" has the same definition as found in Section
816-102 of the Public Utilities Act.
9 "Settlement period" means the period of time utilized by
10MISO and PJM and their successor organizations as the basis
11for settlement calculations in the real-time energy market.
12 "Sourcing agreement" means (i) in the case of an electric
13utility, an agreement between the owner of a clean coal
14facility and such electric utility, which agreement shall have
15terms and conditions meeting the requirements of paragraph (3)
16of subsection (d) of Section 1-75, (ii) in the case of an
17alternative retail electric supplier, an agreement between the
18owner of a clean coal facility and such alternative retail
19electric supplier, which agreement shall have terms and
20conditions meeting the requirements of Section 16-115(d)(5) of
21the Public Utilities Act, and (iii) in case of a gas utility,
22an agreement between the owner of a clean coal SNG brownfield
23facility and the gas utility, which agreement shall have the
24terms and conditions meeting the requirements of subsection
25(h-1) of Section 9-220 of the Public Utilities Act.
26 "Strike price" means a contract price for energy and

HB5856- 26 -LRB103 40655 LNS 73376 b
1renewable energy credits from a new utility-scale wind project
2or a new utility-scale photovoltaic project.
3 "Subscriber" means a person who (i) takes delivery service
4from an electric utility, and (ii) has a subscription of no
5less than 200 watts to a community renewable generation
6project that is located in the electric utility's service
7area. No subscriber's subscriptions may total more than 40% of
8the nameplate capacity of an individual community renewable
9generation project. Entities that are affiliated by virtue of
10a common parent shall not represent multiple subscriptions
11that total more than 40% of the nameplate capacity of an
12individual community renewable generation project.
13 "Subscription" means an interest in a community renewable
14generation project expressed in kilowatts, which is sized
15primarily to offset part or all of the subscriber's
16electricity usage.
17 "Substitute natural gas" or "SNG" means a gas manufactured
18by gasification of hydrocarbon feedstock, which is
19substantially interchangeable in use and distribution with
20conventional natural gas.
21 "Tolling agreement" means a contract of not less than 15
22years between the owner or operator of an energy storage
23system and an electric utility where the electric utility
24contracts for supply and other services from the energy
25storage system.
26 "Total resource cost test" or "TRC test" means a standard

HB5856- 27 -LRB103 40655 LNS 73376 b
1that is met if, for an investment in energy efficiency or
2demand-response measures, the benefit-cost ratio is greater
3than one. The benefit-cost ratio is the ratio of the net
4present value of the total benefits of the program to the net
5present value of the total costs as calculated over the
6lifetime of the measures. A total resource cost test compares
7the sum of avoided electric utility costs, representing the
8benefits that accrue to the system and the participant in the
9delivery of those efficiency measures and including avoided
10costs associated with reduced use of natural gas or other
11fuels, avoided costs associated with reduced water
12consumption, and avoided costs associated with reduced
13operation and maintenance costs, as well as other quantifiable
14societal benefits, to the sum of all incremental costs of
15end-use measures that are implemented due to the program
16(including both utility and participant contributions), plus
17costs to administer, deliver, and evaluate each demand-side
18program, to quantify the net savings obtained by substituting
19the demand-side program for supply resources. In calculating
20avoided costs of power and energy that an electric utility
21would otherwise have had to acquire, reasonable estimates
22shall be included of financial costs likely to be imposed by
23future regulations and legislation on emissions of greenhouse
24gases. In discounting future societal costs and benefits for
25the purpose of calculating net present values, a societal
26discount rate based on actual, long-term Treasury bond yields

HB5856- 28 -LRB103 40655 LNS 73376 b
1should be used. Notwithstanding anything to the contrary, the
2TRC test shall not include or take into account a calculation
3of market price suppression effects or demand reduction
4induced price effects.
5 "Utility-scale solar project" means an electric generating
6facility that:
7 (1) generates electricity using photovoltaic cells;
8 and
9 (2) has a nameplate capacity that is greater than
10 5,000 kilowatts.
11 "Utility-scale wind project" means an electric generating
12facility that:
13 (1) generates electricity using wind; and
14 (2) has a nameplate capacity that is greater than
15 5,000 kilowatts.
16 "Waste Heat to Power Systems" means systems that capture
17and generate electricity from energy that would otherwise be
18lost to the atmosphere without the use of additional fuel.
19 "Zero emission credit" means a tradable credit that
20represents the environmental attributes of one megawatt hour
21of energy produced from a zero emission facility.
22 "Zero emission facility" means a facility that: (1) is
23fueled by nuclear power; and (2) is interconnected with PJM
24Interconnection, LLC or the Midcontinent Independent System
25Operator, Inc., or their successors.
26(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23;

HB5856- 29 -LRB103 40655 LNS 73376 b
1103-380, eff. 1-1-24.)
2 (20 ILCS 3855/1-20)
3 Sec. 1-20. General powers and duties of the Agency.
4 (a) The Agency is authorized to do each of the following:
5 (1) Develop electricity procurement plans to ensure
6 adequate, reliable, affordable, efficient, and
7 environmentally sustainable electric service at the lowest
8 total cost over time, taking into account any benefits of
9 price stability, for electric utilities that on December
10 31, 2005 provided electric service to at least 100,000
11 customers in Illinois and for small multi-jurisdictional
12 electric utilities that (A) on December 31, 2005 served
13 less than 100,000 customers in Illinois and (B) request a
14 procurement plan for their Illinois jurisdictional load.
15 Except as provided in paragraph (1.5) of this subsection
16 (a), the electricity procurement plans shall be updated on
17 an annual basis and shall include electricity generated
18 from renewable resources sufficient to achieve the
19 standards specified in this Act. Beginning with the
20 delivery year commencing June 1, 2017, develop procurement
21 plans to include zero emission credits generated from zero
22 emission facilities sufficient to achieve the standards
23 specified in this Act. Beginning with the delivery year
24 commencing on June 1, 2022, the Agency is authorized to
25 develop carbon mitigation credit procurement plans to

HB5856- 30 -LRB103 40655 LNS 73376 b
1 include carbon mitigation credits generated from
2 carbon-free energy resources sufficient to achieve the
3 standards specified in this Act.
4 (1.5) Develop a long-term renewable resources
5 procurement plan in accordance with subsection (c) of
6 Section 1-75 of this Act for renewable energy credits in
7 amounts sufficient to achieve the standards specified in
8 this Act for delivery years commencing June 1, 2017 and
9 for the programs and renewable energy credits specified in
10 Section 1-56 of this Act. Electricity procurement plans
11 for delivery years commencing after May 31, 2017, shall
12 not include procurement of renewable energy resources.
13 (2) Conduct competitive procurement processes to
14 procure the supply resources identified in the electricity
15 procurement plan, pursuant to Section 16-111.5 of the
16 Public Utilities Act, and, for the delivery year
17 commencing June 1, 2017, conduct procurement processes to
18 procure zero emission credits from zero emission
19 facilities, under subsection (d-5) of Section 1-75 of this
20 Act. For the delivery year commencing June 1, 2022, the
21 Agency is authorized to conduct procurement processes to
22 procure carbon mitigation credits from carbon-free energy
23 resources, under subsection (d-10) of Section 1-75 of this
24 Act.
25 (2.5) Beginning with the procurement for the 2017
26 delivery year, conduct competitive procurement processes

HB5856- 31 -LRB103 40655 LNS 73376 b
1 and implement programs to procure renewable energy credits
2 identified in the long-term renewable resources
3 procurement plan developed and approved under subsection
4 (c) of Section 1-75 of this Act and Section 16-111.5 of the
5 Public Utilities Act.
6 (2.10) Oversee the procurement by electric utilities
7 that served more than 300,000 customers in this State as
8 of January 1, 2019 of renewable energy credits from new
9 renewable energy facilities to be installed, along with
10 energy storage facilities, at or adjacent to the sites of
11 electric generating facilities that burned coal as their
12 primary fuel source as of January 1, 2016 in accordance
13 with subsection (c-5) of Section 1-75 of this Act.
14 (2.15) Oversee the procurement by electric utilities
15 of renewable energy credits from newly modernized or
16 retooled hydropower dams or dams that have been converted
17 to support hydropower generation.
18 (3) Develop electric generation and co-generation
19 facilities that use indigenous coal or renewable
20 resources, or both, financed with bonds issued by the
21 Illinois Finance Authority.
22 (4) Supply electricity from the Agency's facilities at
23 cost to one or more of the following: municipal electric
24 systems, governmental aggregators, or rural electric
25 cooperatives in Illinois.
26 (5) Conduct competitive solicitations to procure

HB5856- 32 -LRB103 40655 LNS 73376 b
1 energy storage credits sufficient to achieve, at minimum,
2 the energy storage standard under Section 1-93.
3 (b) Except as otherwise limited by this Act, the Agency
4has all of the powers necessary or convenient to carry out the
5purposes and provisions of this Act, including without
6limitation, each of the following:
7 (1) To have a corporate seal, and to alter that seal at
8 pleasure, and to use it by causing it or a facsimile to be
9 affixed or impressed or reproduced in any other manner.
10 (2) To use the services of the Illinois Finance
11 Authority necessary to carry out the Agency's purposes.
12 (3) To negotiate and enter into loan agreements and
13 other agreements with the Illinois Finance Authority.
14 (4) To obtain and employ personnel and hire
15 consultants that are necessary to fulfill the Agency's
16 purposes, and to make expenditures for that purpose within
17 the appropriations for that purpose.
18 (5) To purchase, receive, take by grant, gift, devise,
19 bequest, or otherwise, lease, or otherwise acquire, own,
20 hold, improve, employ, use, and otherwise deal in and
21 with, real or personal property whether tangible or
22 intangible, or any interest therein, within the State.
23 (6) To acquire real or personal property, whether
24 tangible or intangible, including without limitation
25 property rights, interests in property, franchises,
26 obligations, contracts, and debt and equity securities,

HB5856- 33 -LRB103 40655 LNS 73376 b
1 and to do so by the exercise of the power of eminent domain
2 in accordance with Section 1-21; except that any real
3 property acquired by the exercise of the power of eminent
4 domain must be located within the State.
5 (7) To sell, convey, lease, exchange, transfer,
6 abandon, or otherwise dispose of, or mortgage, pledge, or
7 create a security interest in, any of its assets,
8 properties, or any interest therein, wherever situated.
9 (8) To purchase, take, receive, subscribe for, or
10 otherwise acquire, hold, make a tender offer for, vote,
11 employ, sell, lend, lease, exchange, transfer, or
12 otherwise dispose of, mortgage, pledge, or grant a
13 security interest in, use, and otherwise deal in and with,
14 bonds and other obligations, shares, or other securities
15 (or interests therein) issued by others, whether engaged
16 in a similar or different business or activity.
17 (9) To make and execute agreements, contracts, and
18 other instruments necessary or convenient in the exercise
19 of the powers and functions of the Agency under this Act,
20 including contracts with any person, including personal
21 service contracts, or with any local government, State
22 agency, or other entity; and all State agencies and all
23 local governments are authorized to enter into and do all
24 things necessary to perform any such agreement, contract,
25 or other instrument with the Agency. No such agreement,
26 contract, or other instrument shall exceed 40 years.

HB5856- 34 -LRB103 40655 LNS 73376 b
1 (10) To lend money, invest and reinvest its funds in
2 accordance with the Public Funds Investment Act, and take
3 and hold real and personal property as security for the
4 payment of funds loaned or invested.
5 (11) To borrow money at such rate or rates of interest
6 as the Agency may determine, issue its notes, bonds, or
7 other obligations to evidence that indebtedness, and
8 secure any of its obligations by mortgage or pledge of its
9 real or personal property, machinery, equipment,
10 structures, fixtures, inventories, revenues, grants, and
11 other funds as provided or any interest therein, wherever
12 situated.
13 (12) To enter into agreements with the Illinois
14 Finance Authority to issue bonds whether or not the income
15 therefrom is exempt from federal taxation.
16 (13) To procure insurance against any loss in
17 connection with its properties or operations in such
18 amount or amounts and from such insurers, including the
19 federal government, as it may deem necessary or desirable,
20 and to pay any premiums therefor.
21 (14) To negotiate and enter into agreements with
22 trustees or receivers appointed by United States
23 bankruptcy courts or federal district courts or in other
24 proceedings involving adjustment of debts and authorize
25 proceedings involving adjustment of debts and authorize
26 legal counsel for the Agency to appear in any such

HB5856- 35 -LRB103 40655 LNS 73376 b
1 proceedings.
2 (15) To file a petition under Chapter 9 of Title 11 of
3 the United States Bankruptcy Code or take other similar
4 action for the adjustment of its debts.
5 (16) To enter into management agreements for the
6 operation of any of the property or facilities owned by
7 the Agency.
8 (17) To enter into an agreement to transfer and to
9 transfer any land, facilities, fixtures, or equipment of
10 the Agency to one or more municipal electric systems,
11 governmental aggregators, or rural electric agencies or
12 cooperatives, for such consideration and upon such terms
13 as the Agency may determine to be in the best interest of
14 the residents of Illinois.
15 (18) To enter upon any lands and within any building
16 whenever in its judgment it may be necessary for the
17 purpose of making surveys and examinations to accomplish
18 any purpose authorized by this Act.
19 (19) To maintain an office or offices at such place or
20 places in the State as it may determine.
21 (20) To request information, and to make any inquiry,
22 investigation, survey, or study that the Agency may deem
23 necessary to enable it effectively to carry out the
24 provisions of this Act.
25 (21) To accept and expend appropriations.
26 (22) To engage in any activity or operation that is

HB5856- 36 -LRB103 40655 LNS 73376 b
1 incidental to and in furtherance of efficient operation to
2 accomplish the Agency's purposes, including hiring
3 employees that the Director deems essential for the
4 operations of the Agency.
5 (23) To adopt, revise, amend, and repeal rules with
6 respect to its operations, properties, and facilities as
7 may be necessary or convenient to carry out the purposes
8 of this Act, subject to the provisions of the Illinois
9 Administrative Procedure Act and Sections 1-22 and 1-35 of
10 this Act.
11 (24) To establish and collect charges and fees as
12 described in this Act.
13 (25) To conduct competitive gasification feedstock
14 procurement processes to procure the feedstocks for the
15 clean coal SNG brownfield facility in accordance with the
16 requirements of Section 1-78 of this Act.
17 (26) To review, revise, and approve sourcing
18 agreements and mediate and resolve disputes between gas
19 utilities and the clean coal SNG brownfield facility
20 pursuant to subsection (h-1) of Section 9-220 of the
21 Public Utilities Act.
22 (27) To request, review and accept proposals, execute
23 contracts, purchase renewable energy credits and otherwise
24 dedicate funds from the Illinois Power Agency Renewable
25 Energy Resources Fund to create and carry out the
26 objectives of the Illinois Solar for All Program in

HB5856- 37 -LRB103 40655 LNS 73376 b
1 accordance with Section 1-56 of this Act.
2 (28) To ensure Illinois residents and business benefit
3 from programs administered by the Agency and are properly
4 protected from any deceptive or misleading marketing
5 practices by participants in the Agency's programs and
6 procurements.
7 (29) To request, review, and accept proposals; execute
8 contracts; and procure energy storage credits.
9 (c) In conducting the procurement of electricity or other
10products, beginning January 1, 2022, the Agency shall not
11procure any products or services from persons or organizations
12that are in violation of the Displaced Energy Workers Bill of
13Rights, as provided under the Energy Community Reinvestment
14Act at the time of the procurement event or fail to comply the
15labor standards established in subparagraph (Q) of paragraph
16(1) of subsection (c) of Section 1-75.
17(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
18 (20 ILCS 3855/1-75)
19 Sec. 1-75. Planning and Procurement Bureau. The Planning
20and Procurement Bureau has the following duties and
21responsibilities:
22 (a) The Planning and Procurement Bureau shall each year,
23beginning in 2008, develop procurement plans and conduct
24competitive procurement processes in accordance with the
25requirements of Section 16-111.5 of the Public Utilities Act

HB5856- 38 -LRB103 40655 LNS 73376 b
1for the eligible retail customers of electric utilities that
2on December 31, 2005 provided electric service to at least
3100,000 customers in Illinois. Beginning with the delivery
4year commencing on June 1, 2017, the Planning and Procurement
5Bureau shall develop plans and processes for the procurement
6of zero emission credits from zero emission facilities in
7accordance with the requirements of subsection (d-5) of this
8Section. Beginning on the effective date of this amendatory
9Act of the 102nd General Assembly, the Planning and
10Procurement Bureau shall develop plans and processes for the
11procurement of carbon mitigation credits from carbon-free
12energy resources in accordance with the requirements of
13subsection (d-10) of this Section. The Planning and
14Procurement Bureau shall also develop procurement plans and
15conduct competitive procurement processes in accordance with
16the requirements of Section 16-111.5 of the Public Utilities
17Act for the eligible retail customers of small
18multi-jurisdictional electric utilities that (i) on December
1931, 2005 served less than 100,000 customers in Illinois and
20(ii) request a procurement plan for their Illinois
21jurisdictional load. This Section shall not apply to a small
22multi-jurisdictional utility until such time as a small
23multi-jurisdictional utility requests the Agency to prepare a
24procurement plan for their Illinois jurisdictional load. For
25the purposes of this Section, the term "eligible retail
26customers" has the same definition as found in Section

HB5856- 39 -LRB103 40655 LNS 73376 b
116-111.5(a) of the Public Utilities Act.
2 Beginning with the plan or plans to be implemented in the
32017 delivery year, the Agency shall no longer include the
4procurement of renewable energy resources in the annual
5procurement plans required by this subsection (a), except as
6provided in subsection (q) of Section 16-111.5 of the Public
7Utilities Act, and shall instead develop a long-term renewable
8resources procurement plan in accordance with subsection (c)
9of this Section and Section 16-111.5 of the Public Utilities
10Act.
11 In accordance with subsection (c-5) of this Section, the
12Planning and Procurement Bureau shall oversee the procurement
13by electric utilities that served more than 300,000 retail
14customers in this State as of January 1, 2019 of renewable
15energy credits from new utility-scale solar projects to be
16installed, along with energy storage facilities, at or
17adjacent to the sites of electric generating facilities that,
18as of January 1, 2016, burned coal as their primary fuel
19source.
20 (1) The Agency shall each year, beginning in 2008, as
21 needed, issue a request for qualifications for experts or
22 expert consulting firms to develop the procurement plans
23 in accordance with Section 16-111.5 of the Public
24 Utilities Act. In order to qualify an expert or expert
25 consulting firm must have:
26 (A) direct previous experience assembling

HB5856- 40 -LRB103 40655 LNS 73376 b
1 large-scale power supply plans or portfolios for
2 end-use customers;
3 (B) an advanced degree in economics, mathematics,
4 engineering, risk management, or a related area of
5 study;
6 (C) 10 years of experience in the electricity
7 sector, including managing supply risk;
8 (D) expertise in wholesale electricity market
9 rules, including those established by the Federal
10 Energy Regulatory Commission and regional transmission
11 organizations;
12 (E) expertise in credit protocols and familiarity
13 with contract protocols;
14 (F) adequate resources to perform and fulfill the
15 required functions and responsibilities; and
16 (G) the absence of a conflict of interest and
17 inappropriate bias for or against potential bidders or
18 the affected electric utilities.
19 (2) The Agency shall each year, as needed, issue a
20 request for qualifications for a procurement administrator
21 to conduct the competitive procurement processes in
22 accordance with Section 16-111.5 of the Public Utilities
23 Act. In order to qualify an expert or expert consulting
24 firm must have:
25 (A) direct previous experience administering a
26 large-scale competitive procurement process;

HB5856- 41 -LRB103 40655 LNS 73376 b
1 (B) an advanced degree in economics, mathematics,
2 engineering, or a related area of study;
3 (C) 10 years of experience in the electricity
4 sector, including risk management experience;
5 (D) expertise in wholesale electricity market
6 rules, including those established by the Federal
7 Energy Regulatory Commission and regional transmission
8 organizations;
9 (E) expertise in credit and contract protocols;
10 (F) adequate resources to perform and fulfill the
11 required functions and responsibilities; and
12 (G) the absence of a conflict of interest and
13 inappropriate bias for or against potential bidders or
14 the affected electric utilities.
15 (3) The Agency shall provide affected utilities and
16 other interested parties with the lists of qualified
17 experts or expert consulting firms identified through the
18 request for qualifications processes that are under
19 consideration to develop the procurement plans and to
20 serve as the procurement administrator. The Agency shall
21 also provide each qualified expert's or expert consulting
22 firm's response to the request for qualifications. All
23 information provided under this subparagraph shall also be
24 provided to the Commission. The Agency may provide by rule
25 for fees associated with supplying the information to
26 utilities and other interested parties. These parties

HB5856- 42 -LRB103 40655 LNS 73376 b
1 shall, within 5 business days, notify the Agency in
2 writing if they object to any experts or expert consulting
3 firms on the lists. Objections shall be based on:
4 (A) failure to satisfy qualification criteria;
5 (B) identification of a conflict of interest; or
6 (C) evidence of inappropriate bias for or against
7 potential bidders or the affected utilities.
8 The Agency shall remove experts or expert consulting
9 firms from the lists within 10 days if there is a
10 reasonable basis for an objection and provide the updated
11 lists to the affected utilities and other interested
12 parties. If the Agency fails to remove an expert or expert
13 consulting firm from a list, an objecting party may seek
14 review by the Commission within 5 days thereafter by
15 filing a petition, and the Commission shall render a
16 ruling on the petition within 10 days. There is no right of
17 appeal of the Commission's ruling.
18 (4) The Agency shall issue requests for proposals to
19 the qualified experts or expert consulting firms to
20 develop a procurement plan for the affected utilities and
21 to serve as procurement administrator.
22 (5) The Agency shall select an expert or expert
23 consulting firm to develop procurement plans based on the
24 proposals submitted and shall award contracts of up to 5
25 years to those selected.
26 (6) The Agency shall select an expert or expert

HB5856- 43 -LRB103 40655 LNS 73376 b
1 consulting firm, with approval of the Commission, to serve
2 as procurement administrator based on the proposals
3 submitted. If the Commission rejects, within 5 days, the
4 Agency's selection, the Agency shall submit another
5 recommendation within 3 days based on the proposals
6 submitted. The Agency shall award a 5-year contract to the
7 expert or expert consulting firm so selected with
8 Commission approval.
9 (b) The experts or expert consulting firms retained by the
10Agency shall, as appropriate, prepare procurement plans, and
11conduct a competitive procurement process as prescribed in
12Section 16-111.5 of the Public Utilities Act, to ensure
13adequate, reliable, affordable, efficient, and environmentally
14sustainable electric service at the lowest total cost over
15time, taking into account any benefits of price stability, for
16eligible retail customers of electric utilities that on
17December 31, 2005 provided electric service to at least
18100,000 customers in the State of Illinois, and for eligible
19Illinois retail customers of small multi-jurisdictional
20electric utilities that (i) on December 31, 2005 served less
21than 100,000 customers in Illinois and (ii) request a
22procurement plan for their Illinois jurisdictional load.
23 (c) Renewable portfolio standard.
24 (1)(A) The Agency shall develop a long-term renewable
25 resources procurement plan that shall include procurement
26 programs and competitive procurement events necessary to

HB5856- 44 -LRB103 40655 LNS 73376 b
1 meet the goals set forth in this subsection (c). The
2 initial long-term renewable resources procurement plan
3 shall be released for comment no later than 160 days after
4 June 1, 2017 (the effective date of Public Act 99-906).
5 The Agency shall review, and may revise on an expedited
6 basis, the long-term renewable resources procurement plan
7 at least every 2 years, which shall be conducted in
8 conjunction with the procurement plan under Section
9 16-111.5 of the Public Utilities Act to the extent
10 practicable to minimize administrative expense. No later
11 than 120 days after the effective date of this amendatory
12 Act of the 103rd General Assembly, the Agency shall
13 release for comment a revision to the long-term renewable
14 resources procurement plan, updating elements of the most
15 recently approved plan as needed to comply with this
16 amendatory Act of the 103rd General Assembly, and any
17 long-term renewable resources procurement plan update
18 published by the Agency but not yet approved by the
19 Illinois Commerce Commission shall be withdrawn. The
20 long-term renewable resources procurement plans shall be
21 subject to review and approval by the Commission under
22 Section 16-111.5 of the Public Utilities Act.
23 (B) Subject to subparagraph (F) of this paragraph (1),
24 the long-term renewable resources procurement plan shall
25 attempt to meet the goals for procurement of renewable
26 energy credits at levels of at least the following overall

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1 percentages: 13% by the 2017 delivery year; increasing by
2 at least 1.5% each delivery year thereafter to at least
3 25% by the 2025 delivery year; increasing by at least 3%
4 each delivery year thereafter to at least 40% by the 2030
5 delivery year, and continuing at no less than 40% for each
6 delivery year thereafter. The Agency shall attempt to
7 procure 50% by delivery year 2040. The Agency shall
8 determine the annual increase between delivery year 2030
9 and delivery year 2040, if any, taking into account energy
10 demand, other energy resources, and other public policy
11 goals. In the event of a conflict between these goals and
12 the new wind, new photovoltaic, and hydropower procurement
13 requirements described in items (i) through (iii) of
14 subparagraph (C) of this paragraph (1), the long-term plan
15 shall prioritize compliance with the new wind, new
16 photovoltaic, and hydropower procurement requirements
17 described in items (i) through (iii) of subparagraph (C)
18 of this paragraph (1) over the annual percentage targets
19 described in this subparagraph (B). The Agency shall not
20 comply with the annual percentage targets described in
21 this subparagraph (B) by procuring renewable energy
22 credits that are unlikely to lead to the development of
23 new renewable resources or new, modernized, or retooled
24 hydropower facilities.
25 For the delivery year beginning June 1, 2017, the
26 procurement plan shall attempt to include, subject to the

HB5856- 46 -LRB103 40655 LNS 73376 b
1 prioritization outlined in this subparagraph (B),
2 cost-effective renewable energy resources equal to at
3 least 13% of each utility's load for eligible retail
4 customers and 13% of the applicable portion of each
5 utility's load for retail customers who are not eligible
6 retail customers, which applicable portion shall equal 50%
7 of the utility's load for retail customers who are not
8 eligible retail customers on February 28, 2017.
9 For the delivery year beginning June 1, 2018, the
10 procurement plan shall attempt to include, subject to the
11 prioritization outlined in this subparagraph (B),
12 cost-effective renewable energy resources equal to at
13 least 14.5% of each utility's load for eligible retail
14 customers and 14.5% of the applicable portion of each
15 utility's load for retail customers who are not eligible
16 retail customers, which applicable portion shall equal 75%
17 of the utility's load for retail customers who are not
18 eligible retail customers on February 28, 2017.
19 For the delivery year beginning June 1, 2019, and for
20 each year thereafter, the procurement plans shall attempt
21 to include, subject to the prioritization outlined in this
22 subparagraph (B), cost-effective renewable energy
23 resources equal to a minimum percentage of each utility's
24 load for all retail customers as follows: 16% by June 1,
25 2019; increasing by 1.5% each year thereafter to 25% by
26 June 1, 2025; and 25% by June 1, 2026; increasing by at

HB5856- 47 -LRB103 40655 LNS 73376 b
1 least 3% each delivery year thereafter to at least 40% by
2 the 2030 delivery year, and continuing at no less than 40%
3 for each delivery year thereafter. The Agency shall
4 attempt to procure 50% by delivery year 2040. The Agency
5 shall determine the annual increase between delivery year
6 2030 and delivery year 2040, if any, taking into account
7 energy demand, other energy resources, and other public
8 policy goals.
9 For each delivery year, the Agency shall first
10 recognize each utility's obligations for that delivery
11 year under existing contracts. Any renewable energy
12 credits under existing contracts, including renewable
13 energy credits as part of renewable energy resources,
14 shall be used to meet the goals set forth in this
15 subsection (c) for the delivery year.
16 (C) The long-term renewable resources procurement plan
17 described in subparagraph (A) of this paragraph (1) shall
18 include the procurement of renewable energy credits from
19 new projects pursuant to the following terms:
20 (i) At least 10,000,000 renewable energy credits
21 delivered annually by the end of the 2021 delivery
22 year, and increasing ratably to reach 45,000,000
23 renewable energy credits delivered annually from new
24 wind and solar projects, from repowered wind projects,
25 or from retooled hydropower facilities by the end of
26 delivery year 2030 such that the goals in subparagraph

HB5856- 48 -LRB103 40655 LNS 73376 b
1 (B) of this paragraph (1) are met entirely by
2 procurements of renewable energy credits from new wind
3 and photovoltaic projects. Of that amount, to the
4 extent possible, the Agency shall endeavor to procure
5 45% from new and repowered wind and hydropower
6 projects and shall procure at least 55% from
7 photovoltaic projects. Of the amount to be procured
8 from photovoltaic projects, the Agency shall procure:
9 at least 50% from solar photovoltaic projects using
10 the program outlined in subparagraph (K) of this
11 paragraph (1) from distributed renewable energy
12 generation devices or community renewable generation
13 projects; at least 47% from utility-scale solar
14 projects; at least 3% from brownfield site
15 photovoltaic projects that are not community renewable
16 generation projects. The Agency may propose
17 adjustments to these percentages, including
18 establishing percentage-based goals for the
19 procurement of renewable energy credits from retooled
20 hydropower facilities and repowered wind projects
21 through its long-term renewable resources plan
22 described in subparagraph (A) of this paragraph (1),
23 as necessary, based on developer interest, market
24 conditions, budget considerations, and other material
25 factors.
26 In developing the long-term renewable resources

HB5856- 49 -LRB103 40655 LNS 73376 b
1 procurement plan, the Agency shall consider other
2 approaches, in addition to competitive procurements,
3 that can be used to procure renewable energy credits
4 from brownfield site photovoltaic projects and thereby
5 help return blighted or contaminated land to
6 productive use while enhancing public health and the
7 well-being of Illinois residents, including those in
8 environmental justice communities, as defined using
9 existing methodologies and findings used by the Agency
10 and its Administrator in its Illinois Solar for All
11 Program. The Agency shall also consider other
12 approaches, in addition to competitive procurements,
13 to procure renewable energy credits from new and
14 existing hydropower facilities to support the
15 development and maintenance of these facilities. The
16 Agency shall explore options to convert existing dams
17 but shall not consider approaches to develop new dams
18 where they do not already exist. To encourage
19 continued operation of utility-scale wind projects,
20 the Agency shall consider and may propose other
21 approaches in addition to competitive procurements to
22 procure renewable energy credits from repowered wind
23 projects.
24 (ii) In any given delivery year, if forecasted
25 expenses are less than the maximum budget available
26 under subparagraph (E) of this paragraph (1), the

HB5856- 50 -LRB103 40655 LNS 73376 b
1 Agency shall continue to procure new renewable energy
2 credits until that budget is exhausted in the manner
3 outlined in item (i) of this subparagraph (C).
4 (iii) For purposes of this Section:
5 "New wind projects" means wind renewable energy
6 facilities that are energized after June 1, 2017 for
7 the delivery year commencing June 1, 2017.
8 "New photovoltaic projects" means photovoltaic
9 renewable energy facilities that are energized after
10 June 1, 2017. Photovoltaic projects developed under
11 Section 1-56 of this Act shall not apply towards the
12 new photovoltaic project requirements in this
13 subparagraph (C).
14 For purposes of calculating whether the Agency has
15 procured enough new wind and solar renewable energy
16 credits required by this subparagraph (C), renewable
17 energy facilities that have a multi-year renewable
18 energy credit delivery contract with the utility
19 through at least delivery year 2030 shall be
20 considered new, however no renewable energy credits
21 from contracts entered into before June 1, 2021 shall
22 be used to calculate whether the Agency has procured
23 the correct proportion of new wind and new solar
24 contracts described in this subparagraph (C) for
25 delivery year 2021 and thereafter.
26 (D) Renewable energy credits shall be cost effective.

HB5856- 51 -LRB103 40655 LNS 73376 b
1 For purposes of this subsection (c), "cost effective"
2 means that the costs of procuring renewable energy
3 resources do not cause the limit stated in subparagraph
4 (E) of this paragraph (1) to be exceeded and, for
5 renewable energy credits procured through a competitive
6 procurement event, do not exceed benchmarks based on
7 market prices for like products in the region. For
8 purposes of this subsection (c), "like products" means
9 contracts for renewable energy credits from the same or
10 substantially similar technology, same or substantially
11 similar vintage (new or existing), the same or
12 substantially similar quantity, and the same or
13 substantially similar contract length and structure.
14 Benchmarks shall reflect development, financing, or
15 related costs resulting from requirements imposed through
16 other provisions of State law, including, but not limited
17 to, requirements in subparagraphs (P) and (Q) of this
18 paragraph (1) and the Renewable Energy Facilities
19 Agricultural Impact Mitigation Act. Confidential
20 benchmarks shall be developed by the procurement
21 administrator, in consultation with the Commission staff,
22 Agency staff, and the procurement monitor and shall be
23 subject to Commission review and approval. If price
24 benchmarks for like products in the region are not
25 available, the procurement administrator shall establish
26 price benchmarks based on publicly available data on

HB5856- 52 -LRB103 40655 LNS 73376 b
1 regional technology costs and expected current and future
2 regional energy prices. Prior to a procurement, the Agency
3 shall ensure that the procurement administrator considers
4 comments from potential bidders regarding inputs,
5 structure, and methodology of the benchmark for the
6 procurement, including costs and risks of development,
7 construction, financing, or other categories as determined
8 by the Agency. In the request for comments on the
9 benchmark, the procurement administrator shall provide all
10 potential bidders with sufficient information about the
11 structure, methodology, and inputs for previous benchmarks
12 to allow for informed comment. The benchmarks in this
13 Section shall not be used to curtail or otherwise reduce
14 contractual obligations entered into by or through the
15 Agency prior to June 1, 2017 (the effective date of Public
16 Act 99-906).
17 (E) For purposes of this subsection (c), the required
18 procurement of cost-effective renewable energy resources
19 for a particular year commencing prior to June 1, 2017
20 shall be measured as a percentage of the actual amount of
21 electricity (megawatt-hours) supplied by the electric
22 utility to eligible retail customers in the delivery year
23 ending immediately prior to the procurement, and, for
24 delivery years commencing on and after June 1, 2017, the
25 required procurement of cost-effective renewable energy
26 resources for a particular year shall be measured as a

HB5856- 53 -LRB103 40655 LNS 73376 b
1 percentage of the actual amount of electricity
2 (megawatt-hours) delivered by the electric utility in the
3 delivery year ending immediately prior to the procurement,
4 to all retail customers in its service territory. For
5 purposes of this subsection (c), the amount paid per
6 kilowatthour means the total amount paid for electric
7 service expressed on a per kilowatthour basis. For
8 purposes of this subsection (c), the total amount paid for
9 electric service includes without limitation amounts paid
10 for supply, transmission, capacity, distribution,
11 surcharges, and add-on taxes.
12 Notwithstanding the requirements of this subsection
13 (c), the total of renewable energy resources procured
14 under the procurement plan for any single year shall be
15 subject to the limitations of this subparagraph (E). Such
16 procurement shall be reduced for all retail customers
17 based on the amount necessary to limit the annual
18 estimated average net increase due to the costs of these
19 resources included in the amounts paid by eligible retail
20 customers in connection with electric service to no more
21 than 4.25% of the amount paid per kilowatthour by those
22 customers during the year ending May 31, 2009. To arrive
23 at a maximum dollar amount of renewable energy resources
24 to be procured for the particular delivery year, the
25 resulting per kilowatthour amount shall be applied to the
26 actual amount of kilowatthours of electricity delivered,

HB5856- 54 -LRB103 40655 LNS 73376 b
1 or applicable portion of such amount as specified in
2 paragraph (1) of this subsection (c), as applicable, by
3 the electric utility in the delivery year immediately
4 prior to the procurement to all retail customers in its
5 service territory. The calculations required by this
6 subparagraph (E) shall be made only once for each delivery
7 year at the time that the renewable energy resources are
8 procured. Once the determination as to the amount of
9 renewable energy resources to procure is made based on the
10 calculations set forth in this subparagraph (E) and the
11 contracts procuring those amounts are executed, no
12 subsequent rate impact determinations shall be made and no
13 adjustments to those contract amounts shall be allowed.
14 All costs incurred under such contracts shall be fully
15 recoverable by the electric utility as provided in this
16 Section. If the limitation on the amount of renewable
17 energy resources procured in this subparagraph (E) would
18 prevent the Agency from meeting the obligations of
19 existing contracts, then the Agency shall use additional
20 funds collected under subsection (k) of Section 16-108 of
21 the Public Utilities Act if so authorized by the
22 Commission in approving the Agency's long-term renewable
23 resources procurement plan. If the Agency notifies the
24 Commission that its existing contractual obligations are
25 reasonably expected to exceed the maximum collection
26 authorized under this subparagraph (E), then the Agency

HB5856- 55 -LRB103 40655 LNS 73376 b
1 shall suspend or reduce new procurements until a new rate
2 impact determination is made pursuant to this subparagraph
3 (E). The utilities shall be entitled to recover the total
4 cost associated with procuring renewable energy credits
5 required by this Section regardless of whether the costs
6 are subject to the limitations described in this
7 subparagraph (E) through the automatic adjustment clause
8 tariff under subsection (k) of Section 16-108 of the
9 Public Utilities Act.
10 (F) If the limitation on the amount of renewable
11 energy resources procured in subparagraph (E) of this
12 paragraph (1) prevents the Agency from meeting all of the
13 goals in this subsection (c), the Agency's long-term plan
14 shall prioritize compliance with the requirements of this
15 subsection (c) regarding renewable energy credits in the
16 following order:
17 (i) renewable energy credits under existing
18 contractual obligations as of June 1, 2021;
19 (i-5) funding for the Illinois Solar for All
20 Program, as described in subparagraph (O) of this
21 paragraph (1);
22 (ii) renewable energy credits necessary to comply
23 with the new wind and new photovoltaic procurement
24 requirements described in items (i) through (iii) of
25 subparagraph (C) of this paragraph (1); and
26 (iii) renewable energy credits necessary to meet

HB5856- 56 -LRB103 40655 LNS 73376 b
1 the remaining requirements of this subsection (c).
2 (G) The following provisions shall apply to the
3 Agency's procurement of renewable energy credits under
4 this subsection (c):
5 (i) Notwithstanding whether a long-term renewable
6 resources procurement plan has been approved, the
7 Agency shall conduct an initial forward procurement
8 for renewable energy credits from new utility-scale
9 wind projects within 160 days after June 1, 2017 (the
10 effective date of Public Act 99-906). For the purposes
11 of this initial forward procurement, the Agency shall
12 solicit 15-year contracts for delivery of 1,000,000
13 renewable energy credits delivered annually from new
14 utility-scale wind projects to begin delivery on June
15 1, 2019, if available, but not later than June 1, 2021,
16 unless the project has delays in the establishment of
17 an operating interconnection with the applicable
18 transmission or distribution system as a result of the
19 actions or inactions of the transmission or
20 distribution provider, or other causes for force
21 majeure as outlined in the procurement contract, in
22 which case, not later than June 1, 2022. Payments to
23 suppliers of renewable energy credits shall commence
24 upon delivery. Renewable energy credits procured under
25 this initial procurement shall be included in the
26 Agency's long-term plan and shall apply to all

HB5856- 57 -LRB103 40655 LNS 73376 b
1 renewable energy goals in this subsection (c).
2 (ii) Notwithstanding whether a long-term renewable
3 resources procurement plan has been approved, the
4 Agency shall conduct an initial forward procurement
5 for renewable energy credits from new utility-scale
6 solar projects and brownfield site photovoltaic
7 projects within one year after June 1, 2017 (the
8 effective date of Public Act 99-906). For the purposes
9 of this initial forward procurement, the Agency shall
10 solicit 15-year contracts for delivery of 1,000,000
11 renewable energy credits delivered annually from new
12 utility-scale solar projects and brownfield site
13 photovoltaic projects to begin delivery on June 1,
14 2019, if available, but not later than June 1, 2021,
15 unless the project has delays in the establishment of
16 an operating interconnection with the applicable
17 transmission or distribution system as a result of the
18 actions or inactions of the transmission or
19 distribution provider, or other causes for force
20 majeure as outlined in the procurement contract, in
21 which case, not later than June 1, 2022. The Agency may
22 structure this initial procurement in one or more
23 discrete procurement events. Payments to suppliers of
24 renewable energy credits shall commence upon delivery.
25 Renewable energy credits procured under this initial
26 procurement shall be included in the Agency's

HB5856- 58 -LRB103 40655 LNS 73376 b
1 long-term plan and shall apply to all renewable energy
2 goals in this subsection (c).
3 (iii) Notwithstanding whether the Commission has
4 approved the periodic long-term renewable resources
5 procurement plan revision described in Section
6 16-111.5 of the Public Utilities Act, the Agency shall
7 conduct at least one subsequent forward procurement
8 for renewable energy credits from new utility-scale
9 wind projects, new utility-scale solar projects, and
10 new brownfield site photovoltaic projects within 240
11 days after the effective date of this amendatory Act
12 of the 102nd General Assembly in quantities necessary
13 to meet the requirements of subparagraph (C) of this
14 paragraph (1) through the delivery year beginning June
15 1, 2021.
16 (iv) Notwithstanding whether the Commission has
17 approved the periodic long-term renewable resources
18 procurement plan revision described in Section
19 16-111.5 of the Public Utilities Act, the Agency shall
20 open capacity for each category in the Adjustable
21 Block program within 90 days after the effective date
22 of this amendatory Act of the 102nd General Assembly
23 manner:
24 (1) The Agency shall open the first block of
25 annual capacity for the category described in item
26 (i) of subparagraph (K) of this paragraph (1). The

HB5856- 59 -LRB103 40655 LNS 73376 b
1 first block of annual capacity for item (i) shall
2 be for at least 75 megawatts of total nameplate
3 capacity. The price of the renewable energy credit
4 for this block of capacity shall be 4% less than
5 the price of the last open block in this category.
6 Projects on a waitlist shall be awarded contracts
7 first in the order in which they appear on the
8 waitlist. Notwithstanding anything to the
9 contrary, for those renewable energy credits that
10 qualify and are procured under this subitem (1) of
11 this item (iv), the renewable energy credit
12 delivery contract value shall be paid in full,
13 based on the estimated generation during the first
14 15 years of operation, by the contracting
15 utilities at the time that the facility producing
16 the renewable energy credits is interconnected at
17 the distribution system level of the utility and
18 verified as energized and in compliance by the
19 Program Administrator. The electric utility shall
20 receive and retire all renewable energy credits
21 generated by the project for the first 15 years of
22 operation. Renewable energy credits generated by
23 the project thereafter shall not be transferred
24 under the renewable energy credit delivery
25 contract with the counterparty electric utility.
26 (2) The Agency shall open the first block of

HB5856- 60 -LRB103 40655 LNS 73376 b
1 annual capacity for the category described in item
2 (ii) of subparagraph (K) of this paragraph (1).
3 The first block of annual capacity for item (ii)
4 shall be for at least 75 megawatts of total
5 nameplate capacity.
6 (A) The price of the renewable energy
7 credit for any project on a waitlist for this
8 category before the opening of this block
9 shall be 4% less than the price of the last
10 open block in this category. Projects on the
11 waitlist shall be awarded contracts first in
12 the order in which they appear on the
13 waitlist. Any projects that are less than or
14 equal to 25 kilowatts in size on the waitlist
15 for this capacity shall be moved to the
16 waitlist for paragraph (1) of this item (iv).
17 Notwithstanding anything to the contrary,
18 projects that were on the waitlist prior to
19 opening of this block shall not be required to
20 be in compliance with the requirements of
21 subparagraph (Q) of this paragraph (1) of this
22 subsection (c). Notwithstanding anything to
23 the contrary, for those renewable energy
24 credits procured from projects that were on
25 the waitlist for this category before the
26 opening of this block 20% of the renewable

HB5856- 61 -LRB103 40655 LNS 73376 b
1 energy credit delivery contract value, based
2 on the estimated generation during the first
3 15 years of operation, shall be paid by the
4 contracting utilities at the time that the
5 facility producing the renewable energy
6 credits is interconnected at the distribution
7 system level of the utility and verified as
8 energized by the Program Administrator. The
9 remaining portion shall be paid ratably over
10 the subsequent 4-year period. The electric
11 utility shall receive and retire all renewable
12 energy credits generated by the project during
13 the first 15 years of operation. Renewable
14 energy credits generated by the project
15 thereafter shall not be transferred under the
16 renewable energy credit delivery contract with
17 the counterparty electric utility.
18 (B) The price of renewable energy credits
19 for any project not on the waitlist for this
20 category before the opening of the block shall
21 be determined and published by the Agency.
22 Projects not on a waitlist as of the opening
23 of this block shall be subject to the
24 requirements of subparagraph (Q) of this
25 paragraph (1), as applicable. Projects not on
26 a waitlist as of the opening of this block

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1 shall be subject to the contract provisions
2 outlined in item (iii) of subparagraph (L) of
3 this paragraph (1). The Agency shall strive to
4 publish updated prices and an updated
5 renewable energy credit delivery contract as
6 quickly as possible.
7 (3) For opening the first 2 blocks of annual
8 capacity for projects participating in item (iii)
9 of subparagraph (K) of paragraph (1) of subsection
10 (c), projects shall be selected exclusively from
11 those projects on the ordinal waitlists of
12 community renewable generation projects
13 established by the Agency based on the status of
14 those ordinal waitlists as of December 31, 2020,
15 and only those projects previously determined to
16 be eligible for the Agency's April 2019 community
17 solar project selection process.
18 The first 2 blocks of annual capacity for item
19 (iii) shall be for 250 megawatts of total
20 nameplate capacity, with both blocks opening
21 simultaneously under the schedule outlined in the
22 paragraphs below. Projects shall be selected as
23 follows:
24 (A) The geographic balance of selected
25 projects shall follow the Group classification
26 found in the Agency's Revised Long-Term

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1 Renewable Resources Procurement Plan, with 70%
2 of capacity allocated to projects on the Group
3 B waitlist and 30% of capacity allocated to
4 projects on the Group A waitlist.
5 (B) Contract awards for waitlisted
6 projects shall be allocated proportionate to
7 the total nameplate capacity amount across
8 both ordinal waitlists associated with that
9 applicant firm or its affiliates, subject to
10 the following conditions.
11 (i) Each applicant firm having a
12 waitlisted project eligible for selection
13 shall receive no less than 500 kilowatts
14 in awarded capacity across all groups, and
15 no approved vendor may receive more than
16 20% of each Group's waitlist allocation.
17 (ii) Each applicant firm, upon
18 receiving an award of program capacity
19 proportionate to its waitlisted capacity,
20 may then determine which waitlisted
21 projects it chooses to be selected for a
22 contract award up to that capacity amount.
23 (iii) Assuming all other program
24 requirements are met, applicant firms may
25 adjust the nameplate capacity of applicant
26 projects without losing waitlist

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1 eligibility, so long as no project is
2 greater than 2,000 kilowatts in size.
3 (iv) Assuming all other program
4 requirements are met, applicant firms may
5 adjust the expected production associated
6 with applicant projects, subject to
7 verification by the Program Administrator.
8 (C) After a review of affiliate
9 information and the current ordinal waitlists,
10 the Agency shall announce the nameplate
11 capacity award amounts associated with
12 applicant firms no later than 90 days after
13 the effective date of this amendatory Act of
14 the 102nd General Assembly.
15 (D) Applicant firms shall submit their
16 portfolio of projects used to satisfy those
17 contract awards no less than 90 days after the
18 Agency's announcement. The total nameplate
19 capacity of all projects used to satisfy that
20 portfolio shall be no greater than the
21 Agency's nameplate capacity award amount
22 associated with that applicant firm. An
23 applicant firm may decline, in whole or in
24 part, its nameplate capacity award without
25 penalty, with such unmet capacity rolled over
26 to the next block opening for project

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1 selection under item (iii) of subparagraph (K)
2 of this subsection (c). Any projects not
3 included in an applicant firm's portfolio may
4 reapply without prejudice upon the next block
5 reopening for project selection under item
6 (iii) of subparagraph (K) of this subsection
7 (c).
8 (E) The renewable energy credit delivery
9 contract shall be subject to the contract and
10 payment terms outlined in item (iv) of
11 subparagraph (L) of this subsection (c).
12 Contract instruments used for this
13 subparagraph shall contain the following
14 terms:
15 (i) Renewable energy credit prices
16 shall be fixed, without further adjustment
17 under any other provision of this Act or
18 for any other reason, at 10% lower than
19 prices applicable to the last open block
20 for this category, inclusive of any adders
21 available for achieving a minimum of 50%
22 of subscribers to the project's nameplate
23 capacity being residential or small
24 commercial customers with subscriptions of
25 below 25 kilowatts in size;
26 (ii) A requirement that a minimum of

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1 50% of subscribers to the project's
2 nameplate capacity be residential or small
3 commercial customers with subscriptions of
4 below 25 kilowatts in size;
5 (iii) Permission for the ability of a
6 contract holder to substitute projects
7 with other waitlisted projects without
8 penalty should a project receive a
9 non-binding estimate of costs to construct
10 the interconnection facilities and any
11 required distribution upgrades associated
12 with that project of greater than 30 cents
13 per watt AC of that project's nameplate
14 capacity. In developing the applicable
15 contract instrument, the Agency may
16 consider whether other circumstances
17 outside of the control of the applicant
18 firm should also warrant project
19 substitution rights.
20 The Agency shall publish a finalized
21 updated renewable energy credit delivery
22 contract developed consistent with these terms
23 and conditions no less than 30 days before
24 applicant firms must submit their portfolio of
25 projects pursuant to item (D).
26 (F) To be eligible for an award, the

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1 applicant firm shall certify that not less
2 than prevailing wage, as determined pursuant
3 to the Illinois Prevailing Wage Act, was or
4 will be paid to employees who are engaged in
5 construction activities associated with a
6 selected project.
7 (4) The Agency shall open the first block of
8 annual capacity for the category described in item
9 (iv) of subparagraph (K) of this paragraph (1).
10 The first block of annual capacity for item (iv)
11 shall be for at least 50 megawatts of total
12 nameplate capacity. Renewable energy credit prices
13 shall be fixed, without further adjustment under
14 any other provision of this Act or for any other
15 reason, at the price in the last open block in the
16 category described in item (ii) of subparagraph
17 (K) of this paragraph (1). Pricing for future
18 blocks of annual capacity for this category may be
19 adjusted in the Agency's second revision to its
20 Long-Term Renewable Resources Procurement Plan.
21 Projects in this category shall be subject to the
22 contract terms outlined in item (iv) of
23 subparagraph (L) of this paragraph (1).
24 (5) The Agency shall open the equivalent of 2
25 years of annual capacity for the category
26 described in item (v) of subparagraph (K) of this

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1 paragraph (1). The first block of annual capacity
2 for item (v) shall be for at least 10 megawatts of
3 total nameplate capacity. Notwithstanding the
4 provisions of item (v) of subparagraph (K) of this
5 paragraph (1), for the purpose of this initial
6 block, the agency shall accept new project
7 applications intended to increase the diversity of
8 areas hosting community solar projects, the
9 business models of projects, and the size of
10 projects, as described by the Agency in its
11 long-term renewable resources procurement plan
12 that is approved as of the effective date of this
13 amendatory Act of the 102nd General Assembly.
14 Projects in this category shall be subject to the
15 contract terms outlined in item (iii) of
16 subsection (L) of this paragraph (1).
17 (6) The Agency shall open the first blocks of
18 annual capacity for the category described in item
19 (vi) of subparagraph (K) of this paragraph (1),
20 with allocations of capacity within the block
21 generally matching the historical share of block
22 capacity allocated between the category described
23 in items (i) and (ii) of subparagraph (K) of this
24 paragraph (1). The first two blocks of annual
25 capacity for item (vi) shall be for at least 75
26 megawatts of total nameplate capacity. The price

HB5856- 69 -LRB103 40655 LNS 73376 b
1 of renewable energy credits for the blocks of
2 capacity shall be 4% less than the price of the
3 last open blocks in the categories described in
4 items (i) and (ii) of subparagraph (K) of this
5 paragraph (1). Pricing for future blocks of annual
6 capacity for this category may be adjusted in the
7 Agency's second revision to its Long-Term
8 Renewable Resources Procurement Plan. Projects in
9 this category shall be subject to the applicable
10 contract terms outlined in items (ii) and (iii) of
11 subparagraph (L) of this paragraph (1).
12 (v) Upon the effective date of this amendatory Act
13 of the 102nd General Assembly, for all competitive
14 procurements and any procurements of renewable energy
15 credit from new utility-scale wind and new
16 utility-scale photovoltaic projects, the Agency shall
17 procure indexed renewable energy credits and direct
18 respondents to offer a strike price.
19 (1) The purchase price of the indexed
20 renewable energy credit payment shall be
21 calculated for each settlement period. That
22 payment, for any settlement period, shall be equal
23 to the difference resulting from subtracting the
24 strike price from the index price for that
25 settlement period. If this difference results in a
26 negative number, the indexed REC counterparty

HB5856- 70 -LRB103 40655 LNS 73376 b
1 shall owe the seller the absolute value multiplied
2 by the quantity of energy produced in the relevant
3 settlement period. If this difference results in a
4 positive number, the seller shall owe the indexed
5 REC counterparty this amount multiplied by the
6 quantity of energy produced in the relevant
7 settlement period.
8 (2) Parties shall cash settle every month,
9 summing up all settlements (both positive and
10 negative, if applicable) for the prior month.
11 (3) To ensure funding in the annual budget
12 established under subparagraph (E) for indexed
13 renewable energy credit procurements for each year
14 of the term of such contracts, which must have a
15 minimum tenure of 20 calendar years, the
16 procurement administrator, Agency, Commission
17 staff, and procurement monitor shall quantify the
18 annual cost of the contract by utilizing an
19 industry-standard, third-party forward price curve
20 for energy at the appropriate hub or load zone,
21 including the estimated magnitude and timing of
22 the price effects related to federal carbon
23 controls. Each forward price curve shall contain a
24 specific value of the forecasted market price of
25 electricity for each annual delivery year of the
26 contract. For procurement planning purposes, the

HB5856- 71 -LRB103 40655 LNS 73376 b
1 impact on the annual budget for the cost of
2 indexed renewable energy credits for each delivery
3 year shall be determined as the expected annual
4 contract expenditure for that year, equaling the
5 difference between (i) the sum across all relevant
6 contracts of the applicable strike price
7 multiplied by contract quantity and (ii) the sum
8 across all relevant contracts of the forward price
9 curve for the applicable load zone for that year
10 multiplied by contract quantity. The contracting
11 utility shall not assume an obligation in excess
12 of the estimated annual cost of the contracts for
13 indexed renewable energy credits. Forward curves
14 shall be revised on an annual basis as updated
15 forward price curves are released and filed with
16 the Commission in the proceeding approving the
17 Agency's most recent long-term renewable resources
18 procurement plan. If the expected contract spend
19 is higher or lower than the total quantity of
20 contracts multiplied by the forward price curve
21 value for that year, the forward price curve shall
22 be updated by the procurement administrator, in
23 consultation with the Agency, Commission staff,
24 and procurement monitors, using then-currently
25 available price forecast data and additional
26 budget dollars shall be obligated or reobligated

HB5856- 72 -LRB103 40655 LNS 73376 b
1 as appropriate.
2 (4) To ensure that indexed renewable energy
3 credit prices remain predictable and affordable,
4 the Agency may consider the institution of a price
5 collar on REC prices paid under indexed renewable
6 energy credit procurements establishing floor and
7 ceiling REC prices applicable to indexed REC
8 contract prices. Any price collars applicable to
9 indexed REC procurements shall be proposed by the
10 Agency through its long-term renewable resources
11 procurement plan.
12 (vi) All procurements under this subparagraph (G),
13 including the procurement of renewable energy credits
14 from hydropower facilities, shall comply with the
15 geographic requirements in subparagraph (I) of this
16 paragraph (1) and shall follow the procurement
17 processes and procedures described in this Section and
18 Section 16-111.5 of the Public Utilities Act to the
19 extent practicable, and these processes and procedures
20 may be expedited to accommodate the schedule
21 established by this subparagraph (G). To ensure the
22 successful development of new utility-scale solar
23 projects and new utility-scale wind projects for
24 procurements under items (i), (ii), (iii), and (v) of
25 this subparagraph (G), a winning bidder or the current
26 seller under contract countersigned by an electric

HB5856- 73 -LRB103 40655 LNS 73376 b
1 utility counterparty may petition the Commission to
2 revise the terms in the contract. Prior to such
3 petition, upon request by the winning bidder or
4 seller, the Agency shall negotiate directly with the
5 winning bidder or seller. If following the direct
6 negotiations, the Agency and the winning bidder reach
7 an agreement on amended terms or strike price and the
8 Agency finds that the amended terms or strike price
9 reflect a change in circumstances since the date of
10 the bid based on circumstances unforeseeable at the
11 time of the bid, upon petition by the winning bidder or
12 current seller, the Commission shall issue an order
13 directing the utility counterparty to execute a form
14 amendment drafted by the Agency with the revised terms
15 or the new strike price. The Agency shall provide the
16 amendment to the utility within 15 business days after
17 the Commission's order and the utility buyer shall
18 execute the amendment not more than 7 calendar days
19 after delivery by the Agency. The Agency shall develop
20 the form amendment following comment by interested
21 parties.
22 (vii) On and after the effective date of this
23 amendatory Act of the 103rd General Assembly, for all
24 procurements of renewable energy credits from
25 hydropower facilities, the Agency shall establish
26 contract terms designed to optimize existing

HB5856- 74 -LRB103 40655 LNS 73376 b
1 hydropower facilities through modernization or
2 retooling and establish new hydropower facilities at
3 existing dams. Procurements made under this item (vii)
4 shall prioritize projects located in designated
5 environmental justice communities, as defined in
6 subsection (b) of Section 1-56 of this Act, or in
7 projects located in units of local government with
8 median incomes that do not exceed 82% of the median
9 income of the State.
10 (H) The procurement of renewable energy resources for
11 a given delivery year shall be reduced as described in
12 this subparagraph (H) if an alternative retail electric
13 supplier meets the requirements described in this
14 subparagraph (H).
15 (i) Within 45 days after June 1, 2017 (the
16 effective date of Public Act 99-906), an alternative
17 retail electric supplier or its successor shall submit
18 an informational filing to the Illinois Commerce
19 Commission certifying that, as of December 31, 2015,
20 the alternative retail electric supplier owned one or
21 more electric generating facilities that generates
22 renewable energy resources as defined in Section 1-10
23 of this Act, provided that such facilities are not
24 powered by wind or photovoltaics, and the facilities
25 generate one renewable energy credit for each megawatt
26 hour megawatthour of energy produced from the

HB5856- 75 -LRB103 40655 LNS 73376 b
1 facility.
2 The informational filing shall identify each
3 facility that was eligible to satisfy the alternative
4 retail electric supplier's obligations under Section
5 16-115D of the Public Utilities Act as described in
6 this item (i).
7 (ii) For a given delivery year, the alternative
8 retail electric supplier may elect to supply its
9 retail customers with renewable energy credits from
10 the facility or facilities described in item (i) of
11 this subparagraph (H) that continue to be owned by the
12 alternative retail electric supplier.
13 (iii) The alternative retail electric supplier
14 shall notify the Agency and the applicable utility, no
15 later than February 28 of the year preceding the
16 applicable delivery year or 15 days after June 1, 2017
17 (the effective date of Public Act 99-906), whichever
18 is later, of its election under item (ii) of this
19 subparagraph (H) to supply renewable energy credits to
20 retail customers of the utility. Such election shall
21 identify the amount of renewable energy credits to be
22 supplied by the alternative retail electric supplier
23 to the utility's retail customers and the source of
24 the renewable energy credits identified in the
25 informational filing as described in item (i) of this
26 subparagraph (H), subject to the following

HB5856- 76 -LRB103 40655 LNS 73376 b
1 limitations:
2 For the delivery year beginning June 1, 2018,
3 the maximum amount of renewable energy credits to
4 be supplied by an alternative retail electric
5 supplier under this subparagraph (H) shall be 68%
6 multiplied by 25% multiplied by 14.5% multiplied
7 by the amount of metered electricity
8 (megawatt-hours) delivered by the alternative
9 retail electric supplier to Illinois retail
10 customers during the delivery year ending May 31,
11 2016.
12 For delivery years beginning June 1, 2019 and
13 each year thereafter, the maximum amount of
14 renewable energy credits to be supplied by an
15 alternative retail electric supplier under this
16 subparagraph (H) shall be 68% multiplied by 50%
17 multiplied by 16% multiplied by the amount of
18 metered electricity (megawatt-hours) delivered by
19 the alternative retail electric supplier to
20 Illinois retail customers during the delivery year
21 ending May 31, 2016, provided that the 16% value
22 shall increase by 1.5% each delivery year
23 thereafter to 25% by the delivery year beginning
24 June 1, 2025, and thereafter the 25% value shall
25 apply to each delivery year.
26 For each delivery year, the total amount of

HB5856- 77 -LRB103 40655 LNS 73376 b
1 renewable energy credits supplied by all alternative
2 retail electric suppliers under this subparagraph (H)
3 shall not exceed 9% of the Illinois target renewable
4 energy credit quantity. The Illinois target renewable
5 energy credit quantity for the delivery year beginning
6 June 1, 2018 is 14.5% multiplied by the total amount of
7 metered electricity (megawatt-hours) delivered in the
8 delivery year immediately preceding that delivery
9 year, provided that the 14.5% shall increase by 1.5%
10 each delivery year thereafter to 25% by the delivery
11 year beginning June 1, 2025, and thereafter the 25%
12 value shall apply to each delivery year.
13 If the requirements set forth in items (i) through
14 (iii) of this subparagraph (H) are met, the charges
15 that would otherwise be applicable to the retail
16 customers of the alternative retail electric supplier
17 under paragraph (6) of this subsection (c) for the
18 applicable delivery year shall be reduced by the ratio
19 of the quantity of renewable energy credits supplied
20 by the alternative retail electric supplier compared
21 to that supplier's target renewable energy credit
22 quantity. The supplier's target renewable energy
23 credit quantity for the delivery year beginning June
24 1, 2018 is 14.5% multiplied by the total amount of
25 metered electricity (megawatt-hours) delivered by the
26 alternative retail supplier in that delivery year,

HB5856- 78 -LRB103 40655 LNS 73376 b
1 provided that the 14.5% shall increase by 1.5% each
2 delivery year thereafter to 25% by the delivery year
3 beginning June 1, 2025, and thereafter the 25% value
4 shall apply to each delivery year.
5 On or before April 1 of each year, the Agency shall
6 annually publish a report on its website that
7 identifies the aggregate amount of renewable energy
8 credits supplied by alternative retail electric
9 suppliers under this subparagraph (H).
10 (I) The Agency shall design its long-term renewable
11 energy procurement plan to maximize the State's interest
12 in the health, safety, and welfare of its residents,
13 including but not limited to minimizing sulfur dioxide,
14 nitrogen oxide, particulate matter and other pollution
15 that adversely affects public health in this State,
16 increasing fuel and resource diversity in this State,
17 enhancing the reliability and resiliency of the
18 electricity distribution system in this State, meeting
19 goals to limit carbon dioxide emissions under federal or
20 State law, and contributing to a cleaner and healthier
21 environment for the citizens of this State. In order to
22 further these legislative purposes, renewable energy
23 credits shall be eligible to be counted toward the
24 renewable energy requirements of this subsection (c) if
25 they are generated from facilities located in this State.
26 The Agency may qualify renewable energy credits from

HB5856- 79 -LRB103 40655 LNS 73376 b
1 facilities located in states adjacent to Illinois or
2 renewable energy credits associated with the electricity
3 generated by a utility-scale wind energy facility or
4 utility-scale photovoltaic facility and transmitted by a
5 qualifying direct current project described in subsection
6 (b-5) of Section 8-406 of the Public Utilities Act to a
7 delivery point on the electric transmission grid located
8 in this State or a state adjacent to Illinois, if the
9 generator demonstrates and the Agency determines that the
10 operation of such facility or facilities will help promote
11 the State's interest in the health, safety, and welfare of
12 its residents based on the public interest criteria
13 described above. For the purposes of this Section,
14 renewable resources that are delivered via a high voltage
15 direct current converter station located in Illinois shall
16 be deemed generated in Illinois at the time and location
17 the energy is converted to alternating current by the high
18 voltage direct current converter station if the high
19 voltage direct current transmission line: (i) after the
20 effective date of this amendatory Act of the 102nd General
21 Assembly, was constructed with a project labor agreement;
22 (ii) is capable of transmitting electricity at 525kv;
23 (iii) has an Illinois converter station located and
24 interconnected in the region of the PJM Interconnection,
25 LLC; (iv) does not operate as a public utility; and (v) if
26 the high voltage direct current transmission line was

HB5856- 80 -LRB103 40655 LNS 73376 b
1 energized after June 1, 2023. To ensure that the public
2 interest criteria are applied to the procurement and given
3 full effect, the Agency's long-term procurement plan shall
4 describe in detail how each public interest factor shall
5 be considered and weighted for facilities located in
6 states adjacent to Illinois.
7 (J) In order to promote the competitive development of
8 renewable energy resources in furtherance of the State's
9 interest in the health, safety, and welfare of its
10 residents, renewable energy credits shall not be eligible
11 to be counted toward the renewable energy requirements of
12 this subsection (c) if they are sourced from a generating
13 unit whose costs were being recovered through rates
14 regulated by this State or any other state or states on or
15 after January 1, 2017. Each contract executed to purchase
16 renewable energy credits under this subsection (c) shall
17 provide for the contract's termination if the costs of the
18 generating unit supplying the renewable energy credits
19 subsequently begin to be recovered through rates regulated
20 by this State or any other state or states; and each
21 contract shall further provide that, in that event, the
22 supplier of the credits must return 110% of all payments
23 received under the contract. Amounts returned under the
24 requirements of this subparagraph (J) shall be retained by
25 the utility and all of these amounts shall be used for the
26 procurement of additional renewable energy credits from

HB5856- 81 -LRB103 40655 LNS 73376 b
1 new wind or new photovoltaic resources as defined in this
2 subsection (c). The long-term plan shall provide that
3 these renewable energy credits shall be procured in the
4 next procurement event.
5 Notwithstanding the limitations of this subparagraph
6 (J), renewable energy credits sourced from generating
7 units that are constructed, purchased, owned, or leased by
8 an electric utility as part of an approved project,
9 program, or pilot under Section 1-56 of this Act shall be
10 eligible to be counted toward the renewable energy
11 requirements of this subsection (c), regardless of how the
12 costs of these units are recovered. As long as a
13 generating unit or an identifiable portion of a generating
14 unit has not had and does not have its costs recovered
15 through rates regulated by this State or any other state,
16 HVDC renewable energy credits associated with that
17 generating unit or identifiable portion thereof shall be
18 eligible to be counted toward the renewable energy
19 requirements of this subsection (c).
20 (K) The long-term renewable resources procurement plan
21 developed by the Agency in accordance with subparagraph
22 (A) of this paragraph (1) shall include an Adjustable
23 Block program for the procurement of renewable energy
24 credits from new photovoltaic projects that are
25 distributed renewable energy generation devices or new
26 photovoltaic community renewable generation projects. The

HB5856- 82 -LRB103 40655 LNS 73376 b
1 Adjustable Block program shall be generally designed to
2 provide for the steady, predictable, and sustainable
3 growth of new solar photovoltaic development in Illinois.
4 To this end, except as otherwise provided in subparagraph
5 (viii) of this paragraph (K), the Adjustable Block program
6 shall provide a transparent annual schedule of prices and
7 quantities to enable the photovoltaic market to scale up
8 and for renewable energy credit prices to adjust at a
9 predictable rate over time. The prices set by the
10 Adjustable Block program can be reflected as a set value
11 or as the product of a formula.
12 The Adjustable Block program shall include for each
13 category of eligible projects for each delivery year: a
14 single block of nameplate capacity, a price for renewable
15 energy credits within that block, and the terms and
16 conditions for securing a spot on a waitlist once the
17 block is fully committed or reserved. Except as outlined
18 below, the waitlist of projects in a given year will carry
19 over to apply to the subsequent year when another block is
20 opened. Only projects energized on or after June 1, 2017
21 shall be eligible for the Adjustable Block program. For
22 each category for each delivery year the Agency shall
23 determine the amount of generation capacity in each block,
24 and the purchase price for each block, provided that the
25 purchase price provided and the total amount of generation
26 in all blocks for all categories shall be sufficient to

HB5856- 83 -LRB103 40655 LNS 73376 b
1 meet the goals in this subsection (c). The Agency shall
2 strive to issue a single block sized to provide for
3 stability and market growth. The Agency shall establish
4 program eligibility requirements that ensure that projects
5 that enter the program are sufficiently mature to indicate
6 a demonstrable path to completion. The Agency may
7 periodically review its prior decisions establishing the
8 amount of generation capacity in each block, and the
9 purchase price for each block, and may propose, on an
10 expedited basis, changes to these previously set values,
11 including but not limited to redistributing these amounts
12 and the available funds as necessary and appropriate,
13 subject to Commission approval as part of the periodic
14 plan revision process described in Section 16-111.5 of the
15 Public Utilities Act. The Agency may define different
16 block sizes, purchase prices, or other distinct terms and
17 conditions for projects located in different utility
18 service territories if the Agency deems it necessary to
19 meet the goals in this subsection (c).
20 The Adjustable Block program shall include the
21 following categories in at least the following amounts:
22 (i) At least 20% from distributed renewable energy
23 generation devices with a nameplate capacity of no
24 more than 25 kilowatts.
25 (ii) At least 20% from distributed renewable
26 energy generation devices with a nameplate capacity of

HB5856- 84 -LRB103 40655 LNS 73376 b
1 more than 25 kilowatts and no more than 5,000
2 kilowatts. The Agency may create sub-categories within
3 this category to account for the differences between
4 projects for small commercial customers, large
5 commercial customers, and public or non-profit
6 customers.
7 (iii) At least 30% from photovoltaic community
8 renewable generation projects. Capacity for this
9 category for the first 2 delivery years after the
10 effective date of this amendatory Act of the 102nd
11 General Assembly shall be allocated to waitlist
12 projects as provided in paragraph (3) of item (iv) of
13 subparagraph (G). Starting in the third delivery year
14 after the effective date of this amendatory Act of the
15 102nd General Assembly or earlier if the Agency
16 determines there is additional capacity needed for to
17 meet previous delivery year requirements, the
18 following shall apply:
19 (1) to advance the interests of all ratepayers
20 in timely development of community renewable
21 generation projects powered by solar photovoltaics
22 procured under this Act, the Agency shall select
23 projects on a first-come, first-serve basis; ,
24 however, the Agency shall, for applications on or
25 after the effective date of this amendatory Act of
26 the 103rd General Assembly, may suggest additional

HB5856- 85 -LRB103 40655 LNS 73376 b
1 methods to prioritize projects according to this
2 item (1). Prioritization methods shall be clear
3 and changes to those methods shall not hinder the
4 steady, predictable, and sustainable growth of
5 projects under this subsection. The Agency shall
6 ensure any project characteristics incentivized by
7 the prioritization method are aligned with the
8 findings of this Act and the price of the
9 associated renewable energy credit adequately
10 compensates the additional costs that may be
11 imposed on a project that are submitted at the
12 same time;
13 (1.5) all projects submitted under this
14 category shall, as part of the initial
15 application, be required to provide, in a form
16 directed by the Agency, proof of site control,
17 land use permits, if necessary, and a signed
18 interconnection agreement;
19 (2) projects shall have subscriptions of 25 kW
20 or less for at least 50% of the facility's
21 nameplate capacity and the Agency shall price the
22 renewable energy credits with that as a factor;
23 (3) projects shall not be colocated with one
24 or more other community renewable generation
25 projects, as defined in the Agency's first revised
26 long-term renewable resources procurement plan

HB5856- 86 -LRB103 40655 LNS 73376 b
1 approved by the Commission on February 18, 2020,
2 such that the aggregate nameplate capacity exceeds
3 5,000 kilowatts; and
4 (4) projects greater than 2 MW may not apply
5 until after the approval of the Agency's revised
6 Long-Term Renewable Resources Procurement Plan
7 after the effective date of this amendatory Act of
8 the 102nd General Assembly.
9 (iv) At least 15% from distributed renewable
10 generation devices or photovoltaic community renewable
11 generation projects installed or on land adjacent to
12 public school land. For the purposes of this item
13 (iv), qualifying projects shall be located on property
14 owned, leased, or subleased by the school or school
15 district or on property owned, leased, or subleased by
16 the school or school district located adjacent to
17 property owned by the school. The Agency may create
18 subcategories within this category to account for the
19 differences between project size or location. Projects
20 located within environmental justice communities or
21 within Organizational Units that fall within Tier 1 or
22 Tier 2 shall be given priority. Each of the Agency's
23 periodic 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

HB5856- 87 -LRB103 40655 LNS 73376 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

HB5856- 88 -LRB103 40655 LNS 73376 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

HB5856- 89 -LRB103 40655 LNS 73376 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

HB5856- 90 -LRB103 40655 LNS 73376 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

HB5856- 91 -LRB103 40655 LNS 73376 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 both approved vendors and equity eligible
19 contractors. The Agency shall not limit or impair
20 assignment of the contract to sell renewable energy
21 credits authorized by subparagraph (L) to another
22 approved vendor, except to the extent that in exchange
23 for price adders or other beneficial terms and
24 conditions, the applicant agrees to only assign to an
25 approved vendor that is, at the time of assignment, an
26 equity eligible contractor. The Agency may create

HB5856- 92 -LRB103 40655 LNS 73376 b
1 subcategories within this category to account for the
2 differences between project size and type. The Agency
3 shall propose to increase the percentage in this item
4 (vi) over time to 40% based on factors, including, but
5 not limited to, the number of equity eligible
6 contractors and capacity used in this item (vi) in
7 previous delivery years.
8 The Agency shall propose a payment structure for
9 contracts executed pursuant to this paragraph under
10 which, upon a demonstration of qualification or need,
11 applicant firms are advanced capital disbursed after
12 contract execution but before the contracted project's
13 energization. The amount or percentage of capital
14 advanced prior to project energization shall be
15 sufficient to both cover any increase in development
16 costs resulting from prevailing wage requirements or
17 project-labor agreements, and designed to overcome
18 barriers in access to capital faced by equity eligible
19 contractors. The amount or percentage of advanced
20 capital may vary by subcategory within this category
21 and by an applicant's demonstration of need, with such
22 levels to be established through the Long-Term
23 Renewable Resources Procurement Plan authorized under
24 subparagraph (A) of paragraph (1) of subsection (c) of
25 this Section.
26 Contracts developed featuring capital advanced

HB5856- 93 -LRB103 40655 LNS 73376 b
1 prior to a project's energization shall feature
2 provisions to ensure both the successful development
3 of applicant projects and the delivery of the
4 renewable energy credits for the full term of the
5 contract, including ongoing collateral requirements
6 and other provisions deemed necessary by the Agency,
7 and may include energization timelines longer than for
8 comparable project types. The percentage or amount of
9 capital advanced prior to project energization shall
10 not operate to increase the overall contract value,
11 however contracts executed under this subparagraph may
12 feature renewable energy credit prices higher than
13 those offered to similar projects participating in
14 other categories. Capital advanced prior to
15 energization shall serve to reduce the ratable
16 payments made after energization under items (ii) and
17 (iii) of subparagraph (L) or payments made for each
18 renewable energy credit delivery under item (iv) of
19 subparagraph (L).
20 (vii) The remaining capacity shall be allocated by
21 the Agency in order to respond to market demand. The
22 Agency shall allocate any discretionary capacity prior
23 to the beginning of each delivery year.
24 (viii) Notwithstanding the preceding, not more than 90
25 days after the effective date of this amendatory Act of
26 the 103rd General Assembly, the Agency shall petition the

HB5856- 94 -LRB103 40655 LNS 73376 b
1 Commission to modify its Long-Term Renewable Resources
2 Procurement Plan as follows:
3 (1) the petition shall include an estimate of
4 the size of blocks authorized under subparagraph
5 (i) of this paragraph (K) through the delivery
6 year beginning in 2030;
7 (2) the petition shall propose that such
8 capacity be made available on a continuous basis,
9 subject to inter-block price reductions proposed
10 by the Agency; and
11 (3) the petition shall propose a methodology
12 for reallocated capacity under the terms of the
13 Agency's Long-Term Renewable Resources Procurement
14 Plan.
15 The Commission shall approve the Agency's petition
16 within 120 days after receiving the petition, with any
17 modifications that the Commission finds are necessary
18 to deploy distributed renewable energy generation
19 devices to meet customer demand and enable the
20 photovoltaic market to scale up and for renewable
21 energy credit prices to adjust at a predictable rate
22 over time.
23 To the extent there is uncontracted capacity from any
24 block in any of categories (i) through (vi) at the end of a
25 delivery year, the Agency shall redistribute that capacity
26 to one or more other categories giving priority to

HB5856- 95 -LRB103 40655 LNS 73376 b
1 categories with projects on a waitlist. The redistributed
2 capacity shall be added to the annual capacity in the
3 subsequent delivery year, and the price for renewable
4 energy credits shall be the price for the new delivery
5 year. Redistributed capacity shall not be considered
6 redistributed when determining whether the goals in this
7 subsection (K) have been met.
8 Notwithstanding anything to the contrary, as the
9 Agency increases the capacity in item (vi) to 40% over
10 time, the Agency may reduce the capacity of items (i)
11 through (v) proportionate to the capacity of the
12 categories of projects in item (vi), to achieve a balance
13 of project types.
14 The Adjustable Block program shall be designed to
15 ensure that renewable energy credits are procured from
16 projects in diverse locations and are not concentrated in
17 a few regional areas.
18 (L) Notwithstanding provisions for advancing capital
19 prior to project energization found in item (vi) of
20 subparagraph (K), the procurement of photovoltaic
21 renewable energy credits under items (i) through (vi) of
22 subparagraph (K) of this paragraph (1) shall otherwise be
23 subject to the following contract and payment terms:
24 (i) (Blank).
25 (i-3) Upon delivery of evidence of an increase of
26 over 100% of non-binding cost estimates for

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1 interconnection from a study or interconnection
2 agreement issued prior to application of a system to
3 the program described in subparagraph (K) of this
4 paragraph (1) to a study or interconnection agreement
5 issued after such application, the approved vendor
6 submitting such application shall be entitled to
7 return of 100% of any performance assurance posted for
8 such system under a contract described in this
9 subparagraph (L).
10 (i-5) The Agency or its program administrator
11 shall complete the review of the materials as the
12 Agency may require to be submitted to trigger the
13 initial payment for a participating system under the
14 renewable energy credit contract no later than 6 weeks
15 after the completed submission.
16 (ii) For those renewable energy credits that
17 qualify and are procured under item (i) of
18 subparagraph (K) of this paragraph (1), and any
19 similar category projects that are procured under item
20 (vi) of subparagraph (K) of this paragraph (1) that
21 qualify and are procured under item (vi), the contract
22 length shall be 15 years. The renewable energy credit
23 delivery contract value shall be paid in full, based
24 on the estimated generation during the first 15 years
25 of operation, by the contracting utilities at the time
26 that the facility producing the renewable energy

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1 credits is interconnected at the distribution system
2 level of the utility and verified as energized and
3 compliant by the Program Administrator. The electric
4 utility shall receive and retire all renewable energy
5 credits generated by the project for the first 15
6 years of operation. Renewable energy credits generated
7 by the project thereafter shall not be transferred
8 under the renewable energy credit delivery contract
9 with the counterparty electric utility.
10 (iii) For those renewable energy credits that
11 qualify and are procured under item (ii) and (v) of
12 subparagraph (K) of this paragraph (1) and any like
13 projects similar category that qualify and are
14 procured under item (vi), the contract length shall be
15 15 years. 15% of the renewable energy credit delivery
16 contract value, based on the estimated generation
17 during the first 15 years of operation, shall be paid
18 by the contracting utilities at the time that the
19 facility 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) For those renewable energy credits that
6 qualify and are procured under items (iii) and (iv) of
7 subparagraph (K) of this paragraph (1), and any like
8 projects that qualify and are procured under item
9 (vi), the renewable energy credit delivery contract
10 length shall be 20 years and shall be paid over the
11 delivery term, not to exceed during each delivery year
12 the contract price multiplied by the estimated annual
13 renewable energy credit generation amount. If
14 generation of renewable energy credits during a
15 delivery year exceeds the estimated annual generation
16 amount, the excess renewable energy credits shall be
17 carried forward to future delivery years and shall not
18 expire during the delivery term. If generation of
19 renewable energy credits during a delivery year,
20 including carried forward excess renewable energy
21 credits, if any, is less than the estimated annual
22 generation amount, payments during such delivery year
23 will not exceed the quantity generated plus the
24 quantity carried forward multiplied by the contract
25 price. The electric utility shall receive all
26 renewable energy credits generated by the project

HB5856- 99 -LRB103 40655 LNS 73376 b
1 during the first 20 years of operation and retire all
2 renewable energy credits paid for under this item (iv)
3 and return at the end of the delivery term all
4 renewable energy credits that were not paid for.
5 Renewable energy credits generated by the project
6 thereafter shall not be transferred under the
7 renewable energy credit delivery contract with the
8 counterparty electric utility. Notwithstanding the
9 preceding, for those projects participating under item
10 (iii) of subparagraph (K), the contract price for a
11 delivery year shall be based on subscription levels as
12 measured on the higher of the first business day of the
13 delivery year or the first business day 6 months after
14 the first business day of the delivery year.
15 Subscription of 90% of nameplate capacity or greater
16 shall be deemed to be fully subscribed for the
17 purposes of this item (iv). For projects receiving a
18 20-year delivery contract, REC prices shall be
19 adjusted downward for consistency with the incentive
20 levels previously determined to be necessary to
21 support projects under 15-year delivery contracts,
22 taking into consideration any additional new
23 requirements placed on the projects, including, but
24 not limited to, labor standards.
25 (v) Each contract shall include provisions to
26 ensure the delivery of the estimated quantity of

HB5856- 100 -LRB103 40655 LNS 73376 b
1 renewable energy credits and ongoing collateral
2 requirements and other provisions deemed appropriate
3 by the Agency.
4 (vi) The utility shall be the counterparty to the
5 contracts executed under this subparagraph (L) that
6 are approved by the Commission under the process
7 described in Section 16-111.5 of the Public Utilities
8 Act. No contract shall be executed for an amount that
9 is less than one renewable energy credit per year.
10 (vii) If, at any time, approved applications for
11 the Adjustable Block program exceed funds collected by
12 the electric utility or would cause the Agency to
13 exceed the limitation described in subparagraph (E) of
14 this paragraph (1) on the amount of renewable energy
15 resources that may be procured, then the Agency may
16 consider future uncommitted funds to be reserved for
17 these contracts on a first-come, first-served basis.
18 (viii) Nothing in this Section shall require the
19 utility to advance any payment or pay any amounts that
20 exceed the actual amount of revenues anticipated to be
21 collected by the utility under paragraph (6) of this
22 subsection (c) and subsection (k) of Section 16-108 of
23 the Public Utilities Act inclusive of eligible funds
24 collected in prior years and alternative compliance
25 payments for use by the utility, and contracts
26 executed under this Section shall expressly

HB5856- 101 -LRB103 40655 LNS 73376 b
1 incorporate this limitation.
2 (ix) Notwithstanding other requirements of this
3 subparagraph (L), no modification shall be required to
4 Adjustable Block program contracts if they were
5 already executed prior to the establishment, approval,
6 and implementation of new contract forms as a result
7 of this amendatory Act of the 102nd General Assembly.
8 (x) Contracts may be assignable, but only to
9 entities first deemed by the Agency to have met
10 program terms and requirements applicable to direct
11 program participation. In developing contracts for the
12 delivery of renewable energy credits, the Agency shall
13 be permitted to establish fees applicable to each
14 contract assignment.
15 (M) The Agency shall be authorized to retain one or
16 more experts or expert consulting firms to develop,
17 administer, implement, operate, and evaluate the
18 Adjustable Block program described in subparagraph (K) of
19 this paragraph (1), and the Agency shall retain the
20 consultant or consultants in the same manner, to the
21 extent practicable, as the Agency retains others to
22 administer provisions of this Act, including, but not
23 limited to, the procurement administrator. The selection
24 of experts and expert consulting firms and the procurement
25 process described in this subparagraph (M) are exempt from
26 the requirements of Section 20-10 of the Illinois

HB5856- 102 -LRB103 40655 LNS 73376 b
1 Procurement Code, under Section 20-10 of that Code. The
2 Agency shall strive to minimize administrative expenses in
3 the implementation of the Adjustable Block program.
4 The Program Administrator may charge application fees
5 to participating firms to cover the cost of program
6 administration. Any application fee amounts shall
7 initially be determined through the long-term renewable
8 resources procurement plan, and modifications to any
9 application fee that deviate more than 25% from the
10 Commission's approved value must be approved by the
11 Commission as a long-term plan revision under Section
12 16-111.5 of the Public Utilities Act. The Agency shall
13 consider stakeholder feedback when making adjustments to
14 application fees and shall notify stakeholders in advance
15 of any planned changes.
16 In addition to covering the costs of program
17 administration, the Agency, in conjunction with its
18 Program Administrator, may also use the proceeds of such
19 fees charged to participating firms to support public
20 education and ongoing regional and national coordination
21 with nonprofit organizations, public bodies, and others
22 engaged in the implementation of renewable energy
23 incentive programs or similar initiatives. This work may
24 include developing papers and reports, hosting regional
25 and national conferences, and other work deemed necessary
26 by the Agency to position the State of Illinois as a

HB5856- 103 -LRB103 40655 LNS 73376 b
1 national leader in renewable energy incentive program
2 development and administration.
3 The Agency and its consultant or consultants shall
4 monitor block activity, share program activity with
5 stakeholders and conduct quarterly meetings to discuss
6 program activity and market conditions. If necessary, the
7 Agency may make prospective administrative adjustments to
8 the Adjustable Block program design, such as making
9 adjustments to purchase prices as necessary to achieve the
10 goals of this subsection (c). Program modifications to any
11 block price that do not deviate from the Commission's
12 approved value by more than 10% shall take effect
13 immediately and are not subject to Commission review and
14 approval. Program modifications to any block price that
15 deviate more than 10% from the Commission's approved value
16 must be approved by the Commission as a long-term plan
17 amendment under Section 16-111.5 of the Public Utilities
18 Act. The Agency shall consider stakeholder feedback when
19 making adjustments to the Adjustable Block design and
20 shall notify stakeholders in advance of any planned
21 changes.
22 The Agency and its program administrators for both the
23 Adjustable Block program and the Illinois Solar for All
24 Program, consistent with the requirements of this
25 subsection (c) and subsection (b) of Section 1-56 of this
26 Act, shall propose the Adjustable Block program terms,

HB5856- 104 -LRB103 40655 LNS 73376 b
1 conditions, and requirements, including the prices to be
2 paid for renewable energy credits, where applicable, and
3 requirements applicable to participating entities and
4 project applications, through the development, review, and
5 approval of the Agency's long-term renewable resources
6 procurement plan described in this subsection (c) and
7 paragraph (5) of subsection (b) of Section 16-111.5 of the
8 Public Utilities Act. Terms, conditions, and requirements
9 for program participation shall include the following:
10 (i) The Agency shall establish a registration
11 process for entities seeking to qualify for
12 program-administered incentive funding and establish
13 baseline qualifications for vendor approval. The
14 Agency must maintain a list of approved entities on
15 each program's website, and may revoke a vendor's
16 ability to receive program-administered incentive
17 funding status upon a determination that the vendor
18 failed to comply with contract terms, the law, or
19 other program requirements.
20 (ii) The Agency shall establish program
21 requirements and minimum contract terms to ensure
22 projects are properly installed and produce their
23 expected amounts of energy. Program requirements may
24 include on-site inspections and photo documentation of
25 projects under construction. The Agency may require
26 repairs, alterations, or additions to remedy any

HB5856- 105 -LRB103 40655 LNS 73376 b
1 material deficiencies discovered. Vendors who have a
2 disproportionately high number of deficient systems
3 may lose their eligibility to continue to receive
4 State-administered incentive funding through Agency
5 programs and procurements.
6 (iii) To discourage deceptive marketing or other
7 bad faith business practices, the Agency may require
8 direct program participants, including agents
9 operating on their behalf, to provide standardized
10 disclosures to a customer prior to that customer's
11 execution of a contract for the development of a
12 distributed generation system or a subscription to a
13 community solar project.
14 (iv) The Agency shall establish one or multiple
15 Consumer Complaints Centers to accept complaints
16 regarding businesses that participate in, or otherwise
17 benefit from, State-administered incentive funding
18 through Agency-administered programs. The Agency shall
19 maintain a public database of complaints with any
20 confidential or particularly sensitive information
21 redacted from public entries.
22 (v) Through a filing in the proceeding for the
23 approval of its long-term renewable energy resources
24 procurement plan, the Agency shall provide an annual
25 written report to the Illinois Commerce Commission
26 documenting the frequency and nature of complaints and

HB5856- 106 -LRB103 40655 LNS 73376 b
1 any enforcement actions taken in response to those
2 complaints.
3 (vi) The Agency shall schedule regular meetings
4 with representatives of the Office of the Attorney
5 General, the Illinois Commerce Commission, consumer
6 protection groups, and other interested stakeholders
7 to share relevant information about consumer
8 protection, project compliance, and complaints
9 received.
10 (vii) To the extent that complaints received
11 implicate the jurisdiction of the Office of the
12 Attorney General, the Illinois Commerce Commission, or
13 local, State, or federal law enforcement, the Agency
14 shall also refer complaints to those entities as
15 appropriate.
16 (N) The Agency shall establish the terms, conditions,
17 and program requirements for photovoltaic community
18 renewable generation projects with a goal to expand access
19 to a broader group of energy consumers, to ensure robust
20 participation opportunities for residential and small
21 commercial customers and those who cannot install
22 renewable energy on their own properties. Subject to
23 reasonable limitations, any plan approved by the
24 Commission shall allow subscriptions to community
25 renewable generation projects to be portable and
26 transferable. For purposes of this subparagraph (N),

HB5856- 107 -LRB103 40655 LNS 73376 b
1 "portable" means that subscriptions may be retained by the
2 subscriber even if the subscriber relocates or changes its
3 address within the same utility service territory; and
4 "transferable" means that a subscriber may assign or sell
5 subscriptions to another person within the same utility
6 service territory.
7 Through the development of its long-term renewable
8 resources procurement plan, the Agency may consider
9 whether community renewable generation projects utilizing
10 technologies other than photovoltaics should be supported
11 through State-administered incentive funding, and may
12 issue requests for information to gauge market demand.
13 Electric utilities shall provide a monetary credit to
14 a subscriber's subsequent bill for service for the
15 proportional output of a community renewable generation
16 project attributable to that subscriber as specified in
17 Section 16-107.5 of the Public Utilities Act.
18 The Agency shall purchase renewable energy credits
19 from subscribed shares of photovoltaic community renewable
20 generation projects through the Adjustable Block program
21 described in subparagraph (K) of this paragraph (1) or
22 through the Illinois Solar for All Program described in
23 Section 1-56 of this Act. The electric utility shall
24 purchase any unsubscribed energy from community renewable
25 generation projects that are Qualifying Facilities ("QF")
26 under the electric utility's tariff for purchasing the

HB5856- 108 -LRB103 40655 LNS 73376 b
1 output from QFs under Public Utilities Regulatory Policies
2 Act of 1978.
3 The owners of and any subscribers to a community
4 renewable generation project shall not be considered
5 public utilities or alternative retail electricity
6 suppliers under the Public Utilities Act solely as a
7 result of their interest in or subscription to a community
8 renewable generation project and shall not be required to
9 become an alternative retail electric supplier by
10 participating in a community renewable generation project
11 with a public utility.
12 (O) For the delivery year beginning June 1, 2018, the
13 long-term renewable resources procurement plan required by
14 this subsection (c) shall provide for the Agency to
15 procure contracts to continue offering the Illinois Solar
16 for All Program described in subsection (b) of Section
17 1-56 of this Act, and the contracts approved by the
18 Commission shall be executed by the utilities that are
19 subject to this subsection (c). The long-term renewable
20 resources procurement plan shall allocate up to
21 $50,000,000 per delivery year to fund the programs, and
22 the plan shall determine the amount of funding to be
23 apportioned to the programs identified in subsection (b)
24 of Section 1-56 of this Act; provided that for the
25 delivery years beginning June 1, 2021, June 1, 2022, and
26 June 1, 2023, the long-term renewable resources

HB5856- 109 -LRB103 40655 LNS 73376 b
1 procurement plan may average the annual budgets over a
2 3-year period to account for program ramp-up. For the
3 delivery years beginning June 1, 2021, June 1, 2024, June
4 1, 2027, and June 1, 2030 and additional $10,000,000 shall
5 be provided to the Department of Commerce and Economic
6 Opportunity to implement the workforce development
7 programs and reporting as outlined in Section 16-108.12 of
8 the Public Utilities Act. In making the determinations
9 required under this subparagraph (O), the Commission shall
10 consider the experience and performance under the programs
11 and any evaluation reports. The Commission shall also
12 provide for an independent evaluation of those programs on
13 a periodic basis that are funded under this subparagraph
14 (O).
15 (P) All programs and procurements under this
16 subsection (c) shall be designed to encourage
17 participating projects to use a diverse and equitable
18 workforce and a diverse set of contractors, including
19 minority-owned businesses, disadvantaged businesses,
20 trade unions, graduates of any workforce training programs
21 administered under this Act, and small businesses.
22 The Agency shall develop a method to optimize
23 procurement of renewable energy credits from proposed
24 utility-scale projects that are located in communities
25 eligible to receive Energy Transition Community Grants
26 pursuant to Section 10-20 of the Energy Community

HB5856- 110 -LRB103 40655 LNS 73376 b
1 Reinvestment Act. If this requirement conflicts with other
2 provisions of law or the Agency determines that full
3 compliance with the requirements of this subparagraph (P)
4 would be unreasonably costly or administratively
5 impractical, the Agency is to propose alternative
6 approaches to achieve development of renewable energy
7 resources in communities eligible to receive Energy
8 Transition Community Grants pursuant to Section 10-20 of
9 the Energy Community Reinvestment Act or seek an exemption
10 from this requirement from the Commission.
11 (Q) Each facility listed in subitems (i) through (ix)
12 of item (1) of this subparagraph (Q) for which a renewable
13 energy credit delivery contract is signed after the
14 effective date of this amendatory Act of the 102nd General
15 Assembly is subject to the following requirements through
16 the Agency's long-term renewable resources procurement
17 plan:
18 (1) Each facility shall be subject to the
19 prevailing wage requirements included in the
20 Prevailing Wage Act. The Agency shall require
21 verification that all construction performed on the
22 facility by the renewable energy credit delivery
23 contract holder, its contractors, or its
24 subcontractors relating to construction of the
25 facility is performed by construction employees
26 receiving an amount for that work equal to or greater

HB5856- 111 -LRB103 40655 LNS 73376 b
1 than the general prevailing rate, as that term is
2 defined in Section 3 of the Prevailing Wage Act. For
3 purposes of this item (1), "house of worship" means
4 property that is both (1) used exclusively by a
5 religious society or body of persons as a place for
6 religious exercise or religious worship and (2)
7 recognized as exempt from taxation pursuant to Section
8 15-40 of the Property Tax Code. This item (1) shall
9 apply to any the following:
10 (i) all new utility-scale wind projects;
11 (ii) all new utility-scale photovoltaic
12 projects;
13 (iii) all new brownfield photovoltaic
14 projects;
15 (iv) all new photovoltaic community renewable
16 energy facilities and any associated energy
17 storage systems that qualify for item (iii) of
18 subparagraph (K) of this paragraph (1);
19 (v) all new community driven community
20 photovoltaic projects and any associated energy
21 storage systems that qualify for item (v) of
22 subparagraph (K) of this paragraph (1);
23 (vi) all new photovoltaic projects on public
24 school land that qualify for item (iv) of
25 subparagraph (K) of this paragraph (1);
26 (vii) all new photovoltaic distributed

HB5856- 112 -LRB103 40655 LNS 73376 b
1 renewable energy generation devices and any
2 associated energy storage systems that (1) qualify
3 for item (i) of subparagraph (K) of this paragraph
4 (1); (2) are not projects that serve single-family
5 or multi-family residential buildings; and (3) are
6 not houses of worship where the aggregate capacity
7 including collocated projects would not exceed 100
8 kilowatts;
9 (viii) all new photovoltaic distributed
10 renewable energy generation devices and any
11 associated energy storage systems that (1) qualify
12 for item (ii) of subparagraph (K) of this
13 paragraph (1); (2) are not projects that serve
14 single-family or multi-family residential
15 buildings; and (3) are not houses of worship where
16 the aggregate capacity including collocated
17 projects would not exceed 100 kilowatts;
18 (ix) all new, modernized, or retooled
19 hydropower facilities.
20 (2) Renewable energy credits procured from new
21 utility-scale wind projects, new utility-scale solar
22 projects, and new brownfield solar projects pursuant
23 to Agency procurement events occurring after the
24 effective date of this amendatory Act of the 102nd
25 General Assembly must be from facilities built by
26 general contractors that must enter into a project

HB5856- 113 -LRB103 40655 LNS 73376 b
1 labor agreement, as defined by this Act, prior to
2 construction. The project labor agreement shall be
3 filed with the Director in accordance with procedures
4 established by the Agency through its long-term
5 renewable resources procurement plan. Any information
6 submitted to the Agency in this item (2) shall be
7 considered commercially sensitive information. At a
8 minimum, the project labor agreement must provide the
9 names, addresses, and occupations of the owner of the
10 plant and the individuals representing the labor
11 organization employees participating in the project
12 labor agreement consistent with the Project Labor
13 Agreements Act. The agreement must also specify the
14 terms and conditions as defined by this Act.
15 (3) It is the intent of this Section to ensure that
16 economic development occurs across Illinois
17 communities, that emerging businesses may grow, and
18 that there is improved access to the clean energy
19 economy by persons who have greater economic burdens
20 to success. The Agency shall take into consideration
21 the unique cost of compliance of this subparagraph (Q)
22 that might be borne by equity eligible contractors,
23 shall include such costs when determining the price of
24 renewable energy credits in the Adjustable Block
25 program, and shall take such costs into consideration
26 in a nondiscriminatory manner when comparing bids for

HB5856- 114 -LRB103 40655 LNS 73376 b
1 competitive procurements. The Agency shall consider
2 costs associated with compliance whether in the
3 development, financing, or construction of projects.
4 The Agency shall periodically review the assumptions
5 in these costs and may adjust prices, in compliance
6 with subparagraph (M) of this paragraph (1).
7 (R) In its long-term renewable resources procurement
8 plan, the Agency shall establish a self-direct renewable
9 portfolio standard compliance program for eligible
10 self-direct customers that purchase renewable energy
11 credits from utility-scale wind and solar projects through
12 long-term agreements for purchase of renewable energy
13 credits as described in this Section. Such long-term
14 agreements may include the purchase of energy or other
15 products on a physical or financial basis and may involve
16 an alternative retail electric supplier as defined in
17 Section 16-102 of the Public Utilities Act. This program
18 shall take effect in the delivery year commencing June 1,
19 2023.
20 (1) For the purposes of this subparagraph:
21 "Eligible self-direct customer" means any retail
22 customers of an electric utility that serves 3,000,000
23 or more retail customers in the State and whose total
24 highest 30-minute demand was more than 10,000
25 kilowatts, or any retail customers of an electric
26 utility that serves less than 3,000,000 retail

HB5856- 115 -LRB103 40655 LNS 73376 b
1 customers but more than 500,000 retail customers in
2 the State and whose total highest 15-minute demand was
3 more than 10,000 kilowatts.
4 "Retail customer" has the meaning set forth in
5 Section 16-102 of the Public Utilities Act and
6 multiple retail customer accounts under the same
7 corporate parent may aggregate their account demands
8 to meet the 10,000 kilowatt threshold. The criteria
9 for determining whether this subparagraph is
10 applicable to a retail customer shall be based on the
11 12 consecutive billing periods prior to the start of
12 the year in which the application is filed.
13 (2) For renewable energy credits to count toward
14 the self-direct renewable portfolio standard
15 compliance program, they must:
16 (i) qualify as renewable energy credits as
17 defined in Section 1-10 of this Act;
18 (ii) be sourced from one or more renewable
19 energy generating facilities that comply with the
20 geographic requirements as set forth in
21 subparagraph (I) of paragraph (1) of subsection
22 (c) as interpreted through the Agency's long-term
23 renewable resources procurement plan, or, where
24 applicable, the geographic requirements that
25 governed utility-scale renewable energy credits at
26 the time the eligible self-direct customer entered

HB5856- 116 -LRB103 40655 LNS 73376 b
1 into the applicable renewable energy credit
2 purchase agreement;
3 (iii) be procured through long-term contracts
4 with term lengths of at least 10 years either
5 directly with the renewable energy generating
6 facility or through a bundled power purchase
7 agreement, a virtual power purchase agreement, an
8 agreement between the renewable generating
9 facility, an alternative retail electric supplier,
10 and the customer, or such other structure as is
11 permissible under this subparagraph (R);
12 (iv) be equivalent in volume to at least 40%
13 of the eligible self-direct customer's usage,
14 determined annually by the eligible self-direct
15 customer's usage during the previous delivery
16 year, measured to the nearest megawatt-hour;
17 (v) be retired by or on behalf of the large
18 energy customer;
19 (vi) be sourced from new utility-scale wind
20 projects or new utility-scale solar projects; and
21 (vii) if the contracts for renewable energy
22 credits are entered into after the effective date
23 of this amendatory Act of the 102nd General
24 Assembly, the new utility-scale wind projects or
25 new utility-scale solar projects must comply with
26 the requirements established in subparagraphs (P)

HB5856- 117 -LRB103 40655 LNS 73376 b
1 and (Q) of paragraph (1) of this subsection (c)
2 and subsection (c-10).
3 (3) The self-direct renewable portfolio standard
4 compliance program shall be designed to allow eligible
5 self-direct customers to procure new renewable energy
6 credits from new utility-scale wind projects or new
7 utility-scale photovoltaic projects. The Agency shall
8 annually determine the amount of utility-scale
9 renewable energy credits it will include each year
10 from the self-direct renewable portfolio standard
11 compliance program, subject to receiving qualifying
12 applications. In making this determination, the Agency
13 shall evaluate publicly available analyses and studies
14 of the potential market size for utility-scale
15 renewable energy long-term purchase agreements by
16 commercial and industrial energy customers and make
17 that report publicly available. If demand for
18 participation in the self-direct renewable portfolio
19 standard compliance program exceeds availability, the
20 Agency shall ensure participation is evenly split
21 between commercial and industrial users to the extent
22 there is sufficient demand from both customer classes.
23 Each renewable energy credit procured pursuant to this
24 subparagraph (R) by a self-direct customer shall
25 reduce the total volume of renewable energy credits
26 the Agency is otherwise required to procure from new

HB5856- 118 -LRB103 40655 LNS 73376 b
1 utility-scale projects pursuant to subparagraph (C) of
2 paragraph (1) of this subsection (c) on behalf of
3 contracting utilities where the eligible self-direct
4 customer is located. The self-direct customer shall
5 file an annual compliance report with the Agency
6 pursuant to terms established by the Agency through
7 its long-term renewable resources procurement plan to
8 be eligible for participation in this program.
9 Customers must provide the Agency with their most
10 recent electricity billing statements or other
11 information deemed necessary by the Agency to
12 demonstrate they are an eligible self-direct customer.
13 (4) The Commission shall approve a reduction in
14 the volumetric charges collected pursuant to Section
15 16-108 of the Public Utilities Act for approved
16 eligible self-direct customers equivalent to the
17 anticipated cost of renewable energy credit deliveries
18 under contracts for new utility-scale wind and new
19 utility-scale solar entered for each delivery year
20 after the large energy customer begins retiring
21 eligible new utility scale renewable energy credits
22 for self-compliance. The self-direct credit amount
23 shall be determined annually and is equal to the
24 estimated portion of the cost authorized by
25 subparagraph (E) of paragraph (1) of this subsection
26 (c) that supported the annual procurement of

HB5856- 119 -LRB103 40655 LNS 73376 b
1 utility-scale renewable energy credits in the prior
2 delivery year using a methodology described in the
3 long-term renewable resources procurement plan,
4 expressed on a per kilowatthour basis, and does not
5 include (i) costs associated with any contracts
6 entered into before the delivery year in which the
7 customer files the initial compliance report to be
8 eligible for participation in the self-direct program,
9 and (ii) costs associated with procuring renewable
10 energy credits through existing and future contracts
11 through the Adjustable Block Program, subsection (c-5)
12 of this Section 1-75, and the Solar for All Program.
13 The Agency shall assist the Commission in determining
14 the current and future costs. The Agency must
15 determine the self-direct credit amount for new and
16 existing eligible self-direct customers and submit
17 this to the Commission in an annual compliance filing.
18 The Commission must approve the self-direct credit
19 amount by June 1, 2023 and June 1 of each delivery year
20 thereafter.
21 (5) Customers described in this subparagraph (R)
22 shall apply, on a form developed by the Agency, to the
23 Agency to be designated as a self-direct eligible
24 customer. Once the Agency determines that a
25 self-direct customer is eligible for participation in
26 the program, the self-direct customer will remain

HB5856- 120 -LRB103 40655 LNS 73376 b
1 eligible until the end of the term of the contract.
2 Thereafter, application may be made not less than 12
3 months before the filing date of the long-term
4 renewable resources procurement plan described in this
5 Act. At a minimum, such application shall contain the
6 following:
7 (i) the customer's certification that, at the
8 time of the customer's application, the customer
9 qualifies to be a self-direct eligible customer,
10 including documents demonstrating that
11 qualification;
12 (ii) the customer's certification that the
13 customer has entered into or will enter into by
14 the beginning of the applicable procurement year,
15 one or more bilateral contracts for new wind
16 projects or new photovoltaic projects, including
17 supporting documentation;
18 (iii) certification that the contract or
19 contracts for new renewable energy resources are
20 long-term contracts with term lengths of at least
21 10 years, including supporting documentation;
22 (iv) certification of the quantities of
23 renewable energy credits that the customer will
24 purchase each year under such contract or
25 contracts, including supporting documentation;
26 (v) proof that the contract is sufficient to

HB5856- 121 -LRB103 40655 LNS 73376 b
1 produce renewable energy credits to be equivalent
2 in volume to at least 40% of the large energy
3 customer's usage from the previous delivery year,
4 measured to the nearest megawatt-hour; and
5 (vi) certification that the customer intends
6 to maintain the contract for the duration of the
7 length of the contract.
8 (6) If a customer receives the self-direct credit
9 but fails to properly procure and retire renewable
10 energy credits as required under this subparagraph
11 (R), the Commission, on petition from the Agency and
12 after notice and hearing, may direct such customer's
13 utility to recover the cost of the wrongfully received
14 self-direct credits plus interest through an adder to
15 charges assessed pursuant to Section 16-108 of the
16 Public Utilities Act. Self-direct customers who
17 knowingly fail to properly procure and retire
18 renewable energy credits and do not notify the Agency
19 are ineligible for continued participation in the
20 self-direct renewable portfolio standard compliance
21 program.
22 (2) (Blank).
23 (3) (Blank).
24 (4) The electric utility shall retire all renewable
25 energy credits used to comply with the standard.
26 (5) Beginning with the 2010 delivery year and ending

HB5856- 122 -LRB103 40655 LNS 73376 b
1 June 1, 2017, an electric utility subject to this
2 subsection (c) shall apply the lesser of the maximum
3 alternative compliance payment rate or the most recent
4 estimated alternative compliance payment rate for its
5 service territory for the corresponding compliance period,
6 established pursuant to subsection (d) of Section 16-115D
7 of the Public Utilities Act to its retail customers that
8 take service pursuant to the electric utility's hourly
9 pricing tariff or tariffs. The electric utility shall
10 retain all amounts collected as a result of the
11 application of the alternative compliance payment rate or
12 rates to such customers, and, beginning in 2011, the
13 utility shall include in the information provided under
14 item (1) of subsection (d) of Section 16-111.5 of the
15 Public Utilities Act the amounts collected under the
16 alternative compliance payment rate or rates for the prior
17 year ending May 31. Notwithstanding any limitation on the
18 procurement of renewable energy resources imposed by item
19 (2) of this subsection (c), the Agency shall increase its
20 spending on the purchase of renewable energy resources to
21 be procured by the electric utility for the next plan year
22 by an amount equal to the amounts collected by the utility
23 under the alternative compliance payment rate or rates in
24 the prior year ending May 31.
25 (6) The electric utility shall be entitled to recover
26 all of its costs associated with the procurement of

HB5856- 123 -LRB103 40655 LNS 73376 b
1 renewable energy credits under plans approved under this
2 Section and Section 16-111.5 of the Public Utilities Act.
3 These costs shall include associated reasonable expenses
4 for implementing the procurement programs, including, but
5 not limited to, the costs of administering and evaluating
6 the Adjustable Block program, through an automatic
7 adjustment clause tariff in accordance with subsection (k)
8 of Section 16-108 of the Public Utilities Act.
9 (7) Renewable energy credits procured from new
10 photovoltaic projects or new distributed renewable energy
11 generation devices under this Section after June 1, 2017
12 (the effective date of Public Act 99-906) must be procured
13 from devices installed by a qualified person in compliance
14 with the requirements of Section 16-128A of the Public
15 Utilities Act and any rules or regulations adopted
16 thereunder.
17 In meeting the renewable energy requirements of this
18 subsection (c), to the extent feasible and consistent with
19 State and federal law, the renewable energy credit
20 procurements, Adjustable Block solar program, and
21 community renewable generation program shall provide
22 employment opportunities for all segments of the
23 population and workforce, including minority-owned and
24 female-owned business enterprises, and shall not,
25 consistent with State and federal law, discriminate based
26 on race or socioeconomic status.

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

HB5856- 125 -LRB103 40655 LNS 73376 b
1 by electric utilities pursuant to this subsection (c-5)
2 shall be funded solely by revenues collected from the Coal
3 to Solar and Energy Storage Initiative Charge provided for
4 in this subsection (c-5) and subsection (i-5) of Section
5 16-108 of the Public Utilities Act, shall not be funded by
6 revenues collected through any of the other funding
7 mechanisms provided for in subsection (c) of this Section,
8 and shall not be subject to the limitation imposed by
9 subsection (c) on charges to retail customers for costs to
10 procure renewable energy resources pursuant to subsection
11 (c), and shall not be subject to any other requirements or
12 limitations of subsection (c).
13 (2) The Agency shall conduct 2 procurement events to
14 select owners of electric generating facilities meeting
15 the eligibility criteria specified in this subsection
16 (c-5) to enter into long-term contracts to sell renewable
17 energy credits to electric utilities serving more than
18 300,000 retail customers in this State as of January 1,
19 2019. The first procurement event shall be conducted no
20 later than March 31, 2022, unless the Agency elects to
21 delay it, until no later than May 1, 2022, due to its
22 overall volume of work, and shall be to select owners of
23 electric generating facilities located in this State and
24 south of federal Interstate Highway 80 that meet the
25 eligibility criteria specified in this subsection (c-5).
26 The second procurement event shall be conducted no sooner

HB5856- 126 -LRB103 40655 LNS 73376 b
1 than September 30, 2022 and no later than October 31, 2022
2 and shall be to select owners of electric generating
3 facilities located anywhere in this State that meet the
4 eligibility criteria specified in this subsection (c-5).
5 The Agency shall establish and announce a time period,
6 which shall begin no later than 30 days prior to the
7 scheduled date for the procurement event, during which
8 applicants may submit applications to be selected as
9 suppliers of renewable energy credits pursuant to this
10 subsection (c-5). The eligibility criteria for selection
11 as a supplier of renewable energy credits pursuant to this
12 subsection (c-5) shall be as follows:
13 (A) The applicant owns an electric generating
14 facility located in this State that: (i) as of January
15 1, 2016, burned coal as its primary fuel to generate
16 electricity; and (ii) has, or had prior to retirement,
17 an electric generating capacity of at least 150
18 megawatts. The electric generating facility can be
19 either: (i) retired as of the date of the procurement
20 event; or (ii) still operating as of the date of the
21 procurement event.
22 (B) The applicant is not (i) an electric
23 cooperative as defined in Section 3-119 of the Public
24 Utilities Act, or (ii) an entity described in
25 subsection (b)(1) of Section 3-105 of the Public
26 Utilities Act, or an association or consortium of or

HB5856- 127 -LRB103 40655 LNS 73376 b
1 an entity owned by entities described in (i) or (ii);
2 and the coal-fueled electric generating facility was
3 at one time owned, in whole or in part, by a public
4 utility as defined in Section 3-105 of the Public
5 Utilities Act.
6 (C) If participating in the first procurement
7 event, the applicant proposes and commits to construct
8 and operate, at the site, and if necessary for
9 sufficient space on property adjacent to the existing
10 property, at which the electric generating facility
11 identified in paragraph (A) is located: (i) a new
12 renewable energy facility of at least 20 megawatts but
13 no more than 100 megawatts of electric generating
14 capacity, and (ii) an energy storage facility having a
15 storage capacity equal to at least 2 megawatts and at
16 most 10 megawatts. If participating in the second
17 procurement event, the applicant proposes and commits
18 to construct and operate, at the site, and if
19 necessary for sufficient space on property adjacent to
20 the existing property, at which the electric
21 generating facility identified in paragraph (A) is
22 located: (i) a new renewable energy facility of at
23 least 5 megawatts but no more than 20 megawatts of
24 electric generating capacity, and (ii) an energy
25 storage facility having a storage capacity equal to at
26 least 0.5 megawatts and at most one megawatt.

HB5856- 128 -LRB103 40655 LNS 73376 b
1 (D) The applicant agrees that the new renewable
2 energy facility and the energy storage facility will
3 be constructed or installed by a qualified entity or
4 entities in compliance with the requirements of
5 subsection (g) of Section 16-128A of the Public
6 Utilities Act and any rules adopted thereunder.
7 (E) The applicant agrees that personnel operating
8 the new renewable energy facility and the energy
9 storage facility will have the requisite skills,
10 knowledge, training, experience, and competence, which
11 may be demonstrated by completion or current
12 participation and ultimate completion by employees of
13 an accredited or otherwise recognized apprenticeship
14 program for the employee's particular craft, trade, or
15 skill, including through training and education
16 courses and opportunities offered by the owner to
17 employees of the coal-fueled electric generating
18 facility or by previous employment experience
19 performing the employee's particular work skill or
20 function.
21 (F) The applicant commits that not less than the
22 prevailing wage, as determined pursuant to the
23 Prevailing Wage Act, will be paid to the applicant's
24 employees engaged in construction activities
25 associated with the new renewable energy facility and
26 the new energy storage facility and to the employees

HB5856- 129 -LRB103 40655 LNS 73376 b
1 of applicant's contractors engaged in construction
2 activities associated with the new renewable energy
3 facility and the new energy storage facility, and
4 that, on or before the commercial operation date of
5 the new renewable energy facility, the applicant shall
6 file a report with the Agency certifying that the
7 requirements of this subparagraph (F) have been met.
8 (G) The applicant commits that if selected, it
9 will negotiate a project labor agreement for the
10 construction of the new renewable energy facility and
11 associated energy storage facility that includes
12 provisions requiring the parties to the agreement to
13 work together to establish diversity threshold
14 requirements and to ensure best efforts to meet
15 diversity targets, improve diversity at the applicable
16 job site, create diverse apprenticeship opportunities,
17 and create opportunities to employ former coal-fired
18 power plant workers.
19 (H) The applicant commits to enter into a contract
20 or contracts for the applicable duration to provide
21 specified numbers of renewable energy credits each
22 year from the new renewable energy facility to
23 electric utilities that served more than 300,000
24 retail customers in this State as of January 1, 2019,
25 at a price of $30 per renewable energy credit. The
26 price per renewable energy credit shall be fixed at

HB5856- 130 -LRB103 40655 LNS 73376 b
1 $30 for the applicable duration and the renewable
2 energy credits shall not be indexed renewable energy
3 credits as provided for in item (v) of subparagraph
4 (G) of paragraph (1) of subsection (c) of Section 1-75
5 of this Act. The applicable duration of each contract
6 shall be 20 years, unless the applicant is physically
7 interconnected to the PJM Interconnection, LLC
8 transmission grid and had a generating capacity of at
9 least 1,200 megawatts as of January 1, 2021, in which
10 case the applicable duration of the contract shall be
11 15 years.
12 (I) The applicant's application is certified by an
13 officer of the applicant and by an officer of the
14 applicant's ultimate parent company, if any.
15 (3) An applicant may submit applications to contract
16 to supply renewable energy credits from more than one new
17 renewable energy facility to be constructed at or adjacent
18 to one or more qualifying electric generating facilities
19 owned by the applicant. The Agency may select new
20 renewable energy facilities to be located at or adjacent
21 to the sites of more than one qualifying electric
22 generation facility owned by an applicant to contract with
23 electric utilities to supply renewable energy credits from
24 such facilities.
25 (4) The Agency shall assess fees to each applicant to
26 recover the Agency's costs incurred in receiving and

HB5856- 131 -LRB103 40655 LNS 73376 b
1 evaluating applications, conducting the procurement event,
2 developing contracts for sale, delivery and purchase of
3 renewable energy credits, and monitoring the
4 administration of such contracts, as provided for in this
5 subsection (c-5), including fees paid to a procurement
6 administrator retained by the Agency for one or more of
7 these purposes.
8 (5) The Agency shall select the applicants and the new
9 renewable energy facilities to contract with electric
10 utilities to supply renewable energy credits in accordance
11 with this subsection (c-5). In the first procurement
12 event, the Agency shall select applicants and new
13 renewable energy facilities to supply renewable energy
14 credits, at a price of $30 per renewable energy credit,
15 aggregating to no less than 400,000 renewable energy
16 credits per year for the applicable duration, assuming
17 sufficient qualifying applications to supply, in the
18 aggregate, at least that amount of renewable energy
19 credits per year; and not more than 580,000 renewable
20 energy credits per year for the applicable duration. In
21 the second procurement event, the Agency shall select
22 applicants and new renewable energy facilities to supply
23 renewable energy credits, at a price of $30 per renewable
24 energy credit, aggregating to no more than 625,000
25 renewable energy credits per year less the amount of
26 renewable energy credits each year contracted for as a

HB5856- 132 -LRB103 40655 LNS 73376 b
1 result of the first procurement event, for the applicable
2 durations. The number of renewable energy credits to be
3 procured as specified in this paragraph (5) shall not be
4 reduced based on renewable energy credits procured in the
5 self-direct renewable energy credit compliance program
6 established pursuant to subparagraph (R) of paragraph (1)
7 of subsection (c) of Section 1-75.
8 (6) The obligation to purchase renewable energy
9 credits from the applicants and their new renewable energy
10 facilities selected by the Agency shall be allocated to
11 the electric utilities based on their respective
12 percentages of kilowatthours delivered to delivery
13 services customers to the aggregate kilowatthour
14 deliveries by the electric utilities to delivery services
15 customers for the year ended December 31, 2021. In order
16 to achieve these allocation percentages between or among
17 the electric utilities, the Agency shall require each
18 applicant that is selected in the procurement event to
19 enter into a contract with each electric utility for the
20 sale and purchase of renewable energy credits from each
21 new renewable energy facility to be constructed and
22 operated by the applicant, with the sale and purchase
23 obligations under the contracts to aggregate to the total
24 number of renewable energy credits per year to be supplied
25 by the applicant from the new renewable energy facility.
26 (7) The Agency shall submit its proposed selection of

HB5856- 133 -LRB103 40655 LNS 73376 b
1 applicants, new renewable energy facilities to be
2 constructed, and renewable energy credit amounts for each
3 procurement event to the Commission for approval. The
4 Commission shall, within 2 business days after receipt of
5 the Agency's proposed selections, approve the proposed
6 selections if it determines that the applicants and the
7 new renewable energy facilities to be constructed meet the
8 selection criteria set forth in this subsection (c-5) and
9 that the Agency seeks approval for contracts of applicable
10 durations aggregating to no more than the maximum amount
11 of renewable energy credits per year authorized by this
12 subsection (c-5) for the procurement event, at a price of
13 $30 per renewable energy credit.
14 (8) The Agency, in conjunction with its procurement
15 administrator if one is retained, the electric utilities,
16 and potential applicants for contracts to produce and
17 supply renewable energy credits pursuant to this
18 subsection (c-5), shall develop a standard form contract
19 for the sale, delivery and purchase of renewable energy
20 credits pursuant to this subsection (c-5). Each contract
21 resulting from the first procurement event shall allow for
22 a commercial operation date for the new renewable energy
23 facility of either June 1, 2023 or June 1, 2024, with such
24 dates subject to adjustment as provided in this paragraph.
25 Each contract resulting from the second procurement event
26 shall provide for a commercial operation date on June 1

HB5856- 134 -LRB103 40655 LNS 73376 b
1 next occurring up to 48 months after execution of the
2 contract. Each contract shall provide that the owner shall
3 receive payments for renewable energy credits for the
4 applicable durations beginning with the commercial
5 operation date of the new renewable energy facility. The
6 form contract shall provide for adjustments to the
7 commercial operation and payment start dates as needed due
8 to any delays in completing the procurement and
9 contracting processes, in finalizing interconnection
10 agreements and installing interconnection facilities, and
11 in obtaining other necessary governmental permits and
12 approvals. The form contract shall be, to the maximum
13 extent possible, consistent with standard electric
14 industry contracts for sale, delivery, and purchase of
15 renewable energy credits while taking into account the
16 specific requirements of this subsection (c-5). The form
17 contract shall provide for over-delivery and
18 under-delivery of renewable energy credits within
19 reasonable ranges during each 12-month period and penalty,
20 default, and enforcement provisions for failure of the
21 selling party to deliver renewable energy credits as
22 specified in the contract and to comply with the
23 requirements of this subsection (c-5). The standard form
24 contract shall specify that all renewable energy credits
25 delivered to the electric utility pursuant to the contract
26 shall be retired. The Agency shall make the proposed

HB5856- 135 -LRB103 40655 LNS 73376 b
1 contracts available for a reasonable period for comment by
2 potential applicants, and shall publish the final form
3 contract at least 30 days before the date of the first
4 procurement event.
5 (9) Coal to Solar and Energy Storage Initiative
6 Charge.
7 (A) By no later than July 1, 2022, each electric
8 utility that served more than 300,000 retail customers
9 in this State as of January 1, 2019 shall file a tariff
10 with the Commission for the billing and collection of
11 a Coal to Solar and Energy Storage Initiative Charge
12 in accordance with subsection (i-5) of Section 16-108
13 of the Public Utilities Act, with such tariff to be
14 effective, following review and approval or
15 modification by the Commission, beginning January 1,
16 2023. The tariff shall provide for the calculation and
17 setting of the electric utility's Coal to Solar and
18 Energy Storage Initiative Charge to collect revenues
19 estimated to be sufficient, in the aggregate, (i) to
20 enable the electric utility to pay for the renewable
21 energy credits it has contracted to purchase in the
22 delivery year beginning June 1, 2023 and each delivery
23 year thereafter from new renewable energy facilities
24 located at the sites of qualifying electric generating
25 facilities, and (ii) to fund the grant payments to be
26 made in each delivery year by the Department of

HB5856- 136 -LRB103 40655 LNS 73376 b
1 Commerce and Economic Opportunity, or any successor
2 department or agency, which shall be referred to in
3 this subsection (c-5) as the Department, pursuant to
4 paragraph (10) of this subsection (c-5). The electric
5 utility's tariff shall provide for the billing and
6 collection of the Coal to Solar and Energy Storage
7 Initiative Charge on each kilowatthour of electricity
8 delivered to its delivery services customers within
9 its service territory and shall provide for an annual
10 reconciliation of revenues collected with actual
11 costs, in accordance with subsection (i-5) of Section
12 16-108 of the Public Utilities Act.
13 (B) Each electric utility shall remit on a monthly
14 basis to the State Treasurer, for deposit in the Coal
15 to Solar and Energy Storage Initiative Fund provided
16 for in this subsection (c-5), the electric utility's
17 collections of the Coal to Solar and Energy Storage
18 Initiative Charge in the amount estimated to be needed
19 by the Department for grant payments pursuant to grant
20 contracts entered into by the Department pursuant to
21 paragraph (10) of this subsection (c-5).
22 (10) Coal to Solar and Energy Storage Initiative Fund.
23 (A) The Coal to Solar and Energy Storage
24 Initiative Fund is established as a special fund in
25 the State treasury. The Coal to Solar and Energy
26 Storage Initiative Fund is authorized to receive, by

HB5856- 137 -LRB103 40655 LNS 73376 b
1 statutory deposit, that portion specified in item (B)
2 of paragraph (9) of this subsection (c-5) of moneys
3 collected by electric utilities through imposition of
4 the Coal to Solar and Energy Storage Initiative Charge
5 required by this subsection (c-5). The Coal to Solar
6 and Energy Storage Initiative Fund shall be
7 administered by the Department to provide grants to
8 support the installation and operation of energy
9 storage facilities at the sites of qualifying electric
10 generating facilities meeting the criteria specified
11 in this paragraph (10).
12 (B) The Coal to Solar and Energy Storage
13 Initiative Fund shall not be subject to sweeps,
14 administrative charges, or chargebacks, including, but
15 not limited to, those authorized under Section 8h of
16 the State Finance Act, that would in any way result in
17 the transfer of those funds from the Coal to Solar and
18 Energy Storage Initiative Fund to any other fund of
19 this State or in having any such funds utilized for any
20 purpose other than the express purposes set forth in
21 this paragraph (10).
22 (C) The Department shall utilize up to
23 $280,500,000 in the Coal to Solar and Energy Storage
24 Initiative Fund for grants, assuming sufficient
25 qualifying applicants, to support installation of
26 energy storage facilities at the sites of up to 3

HB5856- 138 -LRB103 40655 LNS 73376 b
1 qualifying electric generating facilities located in
2 the Midcontinent Independent System Operator, Inc.,
3 region in Illinois and the sites of up to 2 qualifying
4 electric generating facilities located in the PJM
5 Interconnection, LLC region in Illinois that meet the
6 criteria set forth in this subparagraph (C). The
7 criteria for receipt of a grant pursuant to this
8 subparagraph (C) are as follows:
9 (1) the electric generating facility at the
10 site has, or had prior to retirement, an electric
11 generating capacity of at least 150 megawatts;
12 (2) the electric generating facility burns (or
13 burned prior to retirement) coal as its primary
14 source of fuel;
15 (3) if the electric generating facility is
16 retired, it was retired subsequent to January 1,
17 2016;
18 (4) the owner of the electric generating
19 facility has not been selected by the Agency
20 pursuant to this subsection (c-5) of this Section
21 to enter into a contract to sell renewable energy
22 credits to one or more electric utilities from a
23 new renewable energy facility located or to be
24 located at or adjacent to the site at which the
25 electric generating facility is located;
26 (5) the electric generating facility located

HB5856- 139 -LRB103 40655 LNS 73376 b
1 at the site was at one time owned, in whole or in
2 part, by a public utility as defined in Section
3 3-105 of the Public Utilities Act;
4 (6) the electric generating facility at the
5 site is not owned by (i) an electric cooperative
6 as defined in Section 3-119 of the Public
7 Utilities Act, or (ii) an entity described in
8 subsection (b)(1) of Section 3-105 of the Public
9 Utilities Act, or an association or consortium of
10 or an entity owned by entities described in items
11 (i) or (ii);
12 (7) the proposed energy storage facility at
13 the site will have energy storage capacity of at
14 least 37 megawatts;
15 (8) the owner commits to place the energy
16 storage facility into commercial operation on
17 either June 1, 2023, June 1, 2024, or June 1, 2025,
18 with such date subject to adjustment as needed due
19 to any delays in completing the grant contracting
20 process, in finalizing interconnection agreements
21 and in installing interconnection facilities, and
22 in obtaining necessary governmental permits and
23 approvals;
24 (9) the owner agrees that the new energy
25 storage facility will be constructed or installed
26 by a qualified entity or entities consistent with

HB5856- 140 -LRB103 40655 LNS 73376 b
1 the requirements of subsection (g) of Section
2 16-128A of the Public Utilities Act and any rules
3 adopted under that Section;
4 (10) the owner agrees that personnel operating
5 the energy storage facility will have the
6 requisite skills, knowledge, training, experience,
7 and competence, which may be demonstrated by
8 completion or current participation and ultimate
9 completion by employees of an accredited or
10 otherwise recognized apprenticeship program for
11 the employee's particular craft, trade, or skill,
12 including through training and education courses
13 and opportunities offered by the owner to
14 employees of the coal-fueled electric generating
15 facility or by previous employment experience
16 performing the employee's particular work skill or
17 function;
18 (11) the owner commits that not less than the
19 prevailing wage, as determined pursuant to the
20 Prevailing Wage Act, will be paid to the owner's
21 employees engaged in construction activities
22 associated with the new energy storage facility
23 and to the employees of the owner's contractors
24 engaged in construction activities associated with
25 the new energy storage facility, and that, on or
26 before the commercial operation date of the new

HB5856- 141 -LRB103 40655 LNS 73376 b
1 energy storage facility, the owner shall file a
2 report with the Department certifying that the
3 requirements of this subparagraph (11) have been
4 met; and
5 (12) the owner commits that if selected to
6 receive a grant, it will negotiate a project labor
7 agreement for the construction of the new energy
8 storage facility that includes provisions
9 requiring the parties to the agreement to work
10 together to establish diversity threshold
11 requirements and to ensure best efforts to meet
12 diversity targets, improve diversity at the
13 applicable job site, create diverse apprenticeship
14 opportunities, and create opportunities to employ
15 former coal-fired power plant workers.
16 The Department shall accept applications for this
17 grant program until March 31, 2022 and shall announce
18 the award of grants no later than June 1, 2022. The
19 Department shall make the grant payments to a
20 recipient in equal annual amounts for 10 years
21 following the date the energy storage facility is
22 placed into commercial operation. The annual grant
23 payments to a qualifying energy storage facility shall
24 be $110,000 per megawatt of energy storage capacity,
25 with total annual grant payments pursuant to this
26 subparagraph (C) for qualifying energy storage

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1 facilities not to exceed $28,050,000 in any year.
2 (D) Grants of funding for energy storage
3 facilities pursuant to subparagraph (C) of this
4 paragraph (10), from the Coal to Solar and Energy
5 Storage Initiative Fund, shall be memorialized in
6 grant contracts between the Department and the
7 recipient. The grant contracts shall specify the date
8 or dates in each year on which the annual grant
9 payments shall be paid.
10 (E) All disbursements from the Coal to Solar and
11 Energy Storage Initiative Fund shall be made only upon
12 warrants of the Comptroller drawn upon the Treasurer
13 as custodian of the Fund upon vouchers signed by the
14 Director of the Department or by the person or persons
15 designated by the Director of the Department for that
16 purpose. The Comptroller is authorized to draw the
17 warrants upon vouchers so signed. The Treasurer shall
18 accept all written warrants so signed and shall be
19 released from liability for all payments made on those
20 warrants.
21 (11) Diversity, equity, and inclusion plans.
22 (A) Each applicant selected in a procurement event
23 to contract to supply renewable energy credits in
24 accordance with this subsection (c-5) and each owner
25 selected by the Department to receive a grant or
26 grants to support the construction and operation of a

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1 new energy storage facility or facilities in
2 accordance with this subsection (c-5) shall, within 60
3 days following the Commission's approval of the
4 applicant to contract to supply renewable energy
5 credits or within 60 days following execution of a
6 grant contract with the Department, as applicable,
7 submit to the Commission a diversity, equity, and
8 inclusion plan setting forth the applicant's or
9 owner's numeric goals for the diversity composition of
10 its supplier entities for the new renewable energy
11 facility or new energy storage facility, as
12 applicable, which shall be referred to for purposes of
13 this paragraph (11) as the project, and the
14 applicant's or owner's action plan and schedule for
15 achieving those goals.
16 (B) For purposes of this paragraph (11), diversity
17 composition shall be based on the percentage, which
18 shall be a minimum of 25%, of eligible expenditures
19 for contract awards for materials and services (which
20 shall be defined in the plan) to business enterprises
21 owned by minority persons, women, or persons with
22 disabilities as defined in Section 2 of the Business
23 Enterprise for Minorities, Women, and Persons with
24 Disabilities Act, to LGBTQ business enterprises, to
25 veteran-owned business enterprises, and to business
26 enterprises located in environmental justice

HB5856- 144 -LRB103 40655 LNS 73376 b
1 communities. The diversity composition goals of the
2 plan may include eligible expenditures in areas for
3 vendor or supplier opportunities in addition to
4 development and construction of the project, and may
5 exclude from eligible expenditures materials and
6 services with limited market availability, limited
7 production and availability from suppliers in the
8 United States, such as solar panels and storage
9 batteries, and material and services that are subject
10 to critical energy infrastructure or cybersecurity
11 requirements or restrictions. The plan may provide
12 that the diversity composition goals may be met
13 through Tier 1 Direct or Tier 2 subcontracting
14 expenditures or a combination thereof for the project.
15 (C) The plan shall provide for, but not be limited
16 to: (i) internal initiatives, including multi-tier
17 initiatives, by the applicant or owner, or by its
18 engineering, procurement and construction contractor
19 if one is used for the project, which for purposes of
20 this paragraph (11) shall be referred to as the EPC
21 contractor, to enable diverse businesses to be
22 considered fairly for selection to provide materials
23 and services; (ii) requirements for the applicant or
24 owner or its EPC contractor to proactively solicit and
25 utilize diverse businesses to provide materials and
26 services; and (iii) requirements for the applicant or

HB5856- 145 -LRB103 40655 LNS 73376 b
1 owner or its EPC contractor to hire a diverse
2 workforce for the project. The plan shall include a
3 description of the applicant's or owner's diversity
4 recruiting efforts both for the project and for other
5 areas of the applicant's or owner's business
6 operations. The plan shall provide for the imposition
7 of financial penalties on the applicant's or owner's
8 EPC contractor for failure to exercise best efforts to
9 comply with and execute the EPC contractor's diversity
10 obligations under the plan. The plan may provide for
11 the applicant or owner to set aside a portion of the
12 work on the project to serve as an incubation program
13 for qualified businesses, as specified in the plan,
14 owned by minority persons, women, persons with
15 disabilities, LGBTQ persons, and veterans, and
16 businesses located in environmental justice
17 communities, seeking to enter the renewable energy
18 industry.
19 (D) The applicant or owner may submit a revised or
20 updated plan to the Commission from time to time as
21 circumstances warrant. The applicant or owner shall
22 file annual reports with the Commission detailing the
23 applicant's or owner's progress in implementing its
24 plan and achieving its goals and any modifications the
25 applicant or owner has made to its plan to better
26 achieve its diversity, equity and inclusion goals. The

HB5856- 146 -LRB103 40655 LNS 73376 b
1 applicant or owner shall file a final report on the
2 fifth June 1 following the commercial operation date
3 of the new renewable energy resource or new energy
4 storage facility, but the applicant or owner shall
5 thereafter continue to be subject to applicable
6 reporting requirements of Section 5-117 of the Public
7 Utilities Act.
8 (c-10) Equity accountability system. It is the purpose of
9this subsection (c-10) to create an equity accountability
10system, which includes the minimum equity standards for all
11renewable energy procurements, the equity category of the
12Adjustable Block Program, and the equity prioritization for
13noncompetitive procurements, that is successful in advancing
14priority access to the clean energy economy for businesses and
15workers from communities that have been excluded from economic
16opportunities in the energy sector, have been subject to
17disproportionate levels of pollution, and have
18disproportionately experienced negative public health
19outcomes. Further, it is the purpose of this subsection to
20ensure that this equity accountability system is successful in
21advancing equity across Illinois by providing access to the
22clean energy economy for businesses and workers from
23communities that have been historically excluded from economic
24opportunities in the energy sector, have been subject to
25disproportionate levels of pollution, and have
26disproportionately experienced negative public health

HB5856- 147 -LRB103 40655 LNS 73376 b
1outcomes.
2 (1) Minimum equity standards. The Agency shall create
3 programs with the purpose of increasing access to and
4 development of equity eligible contractors, who are prime
5 contractors and subcontractors, across all of the programs
6 it manages. All applications for renewable energy credit
7 procurements shall comply with specific minimum equity
8 commitments. Starting in the delivery year immediately
9 following the next long-term renewable resources
10 procurement plan, at least 10% of the project workforce
11 for each entity participating in a procurement program
12 outlined in this subsection (c-10) must be done by equity
13 eligible persons or equity eligible contractors. The
14 Agency shall increase the minimum percentage each delivery
15 year thereafter by increments that ensure a statewide
16 average of 30% of the project workforce for each entity
17 participating in a procurement program is done by equity
18 eligible persons or equity eligible contractors by 2030.
19 The Agency shall propose a schedule of percentage
20 increases to the minimum equity standards in its draft
21 revised renewable energy resources procurement plan
22 submitted to the Commission for approval pursuant to
23 paragraph (5) of subsection (b) of Section 16-111.5 of the
24 Public Utilities Act. In determining these annual
25 increases, the Agency shall have the discretion to
26 establish different minimum equity standards for different

HB5856- 148 -LRB103 40655 LNS 73376 b
1 types of procurements and different regions of the State
2 if the Agency finds that doing so will further the
3 purposes of this subsection (c-10). The proposed schedule
4 of annual increases shall be revisited and updated on an
5 annual basis. Revisions shall be developed with
6 stakeholder input, including from equity eligible persons,
7 equity eligible contractors, clean energy industry
8 representatives, and community-based organizations that
9 work with such persons and contractors.
10 (A) At the start of each delivery year, the Agency
11 shall require a compliance plan from each entity
12 participating in a procurement program of subsection
13 (c) of this Section that demonstrates how they will
14 achieve compliance with the minimum equity standard
15 percentage for work completed in that delivery year.
16 If an entity applies for its approved vendor or
17 designee status between delivery years, the Agency
18 shall require a compliance plan at the time of
19 application.
20 (B) Halfway through each delivery year, the Agency
21 shall require each entity participating in a
22 procurement program to confirm that it will achieve
23 compliance in that delivery year, when applicable. The
24 Agency may offer corrective action plans to entities
25 that are not on track to achieve compliance.
26 (C) At the end of each delivery year, each entity

HB5856- 149 -LRB103 40655 LNS 73376 b
1 participating and completing work in that delivery
2 year in a procurement program of subsection (c) shall
3 submit a report to the Agency that demonstrates how it
4 achieved compliance with the minimum equity standards
5 percentage for that delivery year.
6 (D) The Agency shall prohibit participation in
7 procurement programs by an approved vendor or
8 designee, as applicable, or entities with which an
9 approved vendor or designee, as applicable, shares a
10 common parent company if an approved vendor or
11 designee, as applicable, failed to meet the minimum
12 equity standards for the prior delivery year. Waivers
13 approved for lack of equity eligible persons or equity
14 eligible contractors in a geographic area of a project
15 shall not count against the approved vendor or
16 designee. The Agency shall offer a corrective action
17 plan for any such entities to assist them in obtaining
18 compliance and shall allow continued access to
19 procurement programs upon an approved vendor or
20 designee demonstrating compliance.
21 (E) The Agency shall pursue efficiencies achieved
22 by combining with other approved vendor or designee
23 reporting.
24 (2) Equity accountability system within the Adjustable
25 Block program. The equity category described in item (vi)
26 of subparagraph (K) of subsection (c) is only available to

HB5856- 150 -LRB103 40655 LNS 73376 b
1 applicants that are equity eligible contractors.
2 (3) Equity accountability system within competitive
3 procurements. Through its long-term renewable resources
4 procurement plan, the Agency shall develop requirements
5 for ensuring that competitive procurement processes,
6 including utility-scale solar, utility-scale wind, and
7 brownfield site photovoltaic projects, advance the equity
8 goals of this subsection (c-10). Subject to Commission
9 approval, the Agency shall develop bid application
10 requirements and a bid evaluation methodology for ensuring
11 that utilization of equity eligible contractors, whether
12 as bidders or as participants on project development, is
13 optimized, including requiring that winning or successful
14 applicants for utility-scale projects are or will partner
15 with equity eligible contractors and giving preference to
16 bids through which a higher portion of contract value
17 flows to equity eligible contractors. To the extent
18 practicable, entities participating in competitive
19 procurements shall also be required to meet all the equity
20 accountability requirements for approved vendors and their
21 designees under this subsection (c-10). In developing
22 these requirements, the Agency shall also consider whether
23 equity goals can be further advanced through additional
24 measures.
25 (4) In the first revision to the long-term renewable
26 energy resources procurement plan and each revision

HB5856- 151 -LRB103 40655 LNS 73376 b
1 thereafter, the Agency shall include the following:
2 (A) The current status and number of equity
3 eligible contractors listed in the Energy Workforce
4 Equity Database designed in subsection (c-25),
5 including the number of equity eligible contractors
6 with current certifications as issued by the Agency.
7 (B) A mechanism for measuring, tracking, and
8 reporting project workforce at the approved vendor or
9 designee level, as applicable, which shall include a
10 measurement methodology and records to be made
11 available for audit by the Agency or the Program
12 Administrator.
13 (C) A program for approved vendors, designees,
14 eligible persons, and equity eligible contractors to
15 receive trainings, guidance, and other support from
16 the Agency or its designee regarding the equity
17 category outlined in item (vi) of subparagraph (K) of
18 paragraph (1) of subsection (c) and in meeting the
19 minimum equity standards of this subsection (c-10).
20 (D) A process for certifying equity eligible
21 contractors and equity eligible persons. The
22 certification process shall coordinate with the Energy
23 Workforce Equity Database set forth in subsection
24 (c-25).
25 (E) An application for waiver of the minimum
26 equity standards of this subsection, which the Agency

HB5856- 152 -LRB103 40655 LNS 73376 b
1 shall have the discretion to grant in rare
2 circumstances. The Agency may grant such a waiver
3 where the applicant provides evidence of significant
4 efforts toward meeting the minimum equity commitment,
5 including: use of the Energy Workforce Equity
6 Database; efforts to hire or contract with entities
7 that hire eligible persons; and efforts to establish
8 contracting relationships with eligible contractors.
9 The Agency shall support applicants in understanding
10 the Energy Workforce Equity Database and other
11 resources for pursuing compliance of the minimum
12 equity standards. Waivers shall be project-specific,
13 unless the Agency deems it necessary to grant a waiver
14 across a portfolio of projects, and in effect for no
15 longer than one year. Any waiver extension or
16 subsequent waiver request from an applicant shall be
17 subject to the requirements of this Section and shall
18 specify efforts made to reach compliance. When
19 considering whether to grant a waiver, and to what
20 extent, the Agency shall consider the degree to which
21 similarly situated applicants have been able to meet
22 these minimum equity commitments. For repeated waiver
23 requests for specific lack of eligible persons or
24 eligible contractors available, the Agency shall make
25 recommendations to target recruitment to add such
26 eligible persons or eligible contractors to the

HB5856- 153 -LRB103 40655 LNS 73376 b
1 database.
2 (5) The Agency shall collect information about work on
3 projects or portfolios of projects subject to these
4 minimum equity standards to ensure compliance with this
5 subsection (c-10). Reporting in furtherance of this
6 requirement may be combined with other annual reporting
7 requirements. Such reporting shall include proof of
8 certification of each equity eligible contractor or equity
9 eligible person during the applicable time period.
10 (6) The Agency shall keep confidential all information
11 and communication that provides private or personal
12 information.
13 (7) Modifications to the equity accountability system.
14 As part of the update of the long-term renewable resources
15 procurement plan to be initiated in 2023, or sooner if the
16 Agency deems necessary, the Agency shall determine the
17 extent to which the equity accountability system described
18 in this subsection (c-10) has advanced the goals of this
19 amendatory Act of the 102nd General Assembly, including
20 through the inclusion of equity eligible persons and
21 equity eligible contractors in renewable energy credit
22 projects. If the Agency finds that the equity
23 accountability system has failed to meet those goals to
24 its fullest potential, the Agency may revise the following
25 criteria for future Agency procurements: (A) the
26 percentage of project workforce, or other appropriate

HB5856- 154 -LRB103 40655 LNS 73376 b
1 workforce measure, certified as equity eligible persons or
2 equity eligible contractors; (B) definitions for equity
3 investment eligible persons and equity investment eligible
4 community; and (C) such other modifications necessary to
5 advance the goals of this amendatory Act of the 102nd
6 General Assembly effectively. Such revised criteria may
7 also establish distinct equity accountability systems for
8 different types of procurements or different regions of
9 the State if the Agency finds that doing so will further
10 the purposes of such programs. Revisions shall be
11 developed with stakeholder input, including from equity
12 eligible persons, equity eligible contractors, and
13 community-based organizations that work with such persons
14 and contractors.
15 (c-15) Racial discrimination elimination powers and
16process.
17 (1) Purpose. It is the purpose of this subsection to
18 empower the Agency and other State actors to remedy racial
19 discrimination in Illinois' clean energy economy as
20 effectively and expediently as possible, including through
21 the use of race-conscious remedies, such as race-conscious
22 contracting and hiring goals, as consistent with State and
23 federal law.
24 (2) Racial disparity and discrimination review
25 process.
26 (A) Within one year after awarding contracts using

HB5856- 155 -LRB103 40655 LNS 73376 b
1 the equity actions processes established in this
2 Section, the Agency shall publish a report evaluating
3 the effectiveness of the equity actions point criteria
4 of this Section in increasing participation of equity
5 eligible persons and equity eligible contractors. The
6 report shall disaggregate participating workers and
7 contractors by race and ethnicity. The report shall be
8 forwarded to the Governor, the General Assembly, and
9 the Illinois Commerce Commission and be made available
10 to the public.
11 (B) As soon as is practicable thereafter, the
12 Agency, in consultation with the Department of
13 Commerce and Economic Opportunity, Department of
14 Labor, and other agencies that may be relevant, shall
15 commission and publish a disparity and availability
16 study that measures the presence and impact of
17 discrimination on minority businesses and workers in
18 Illinois' clean energy economy. The Agency may hire
19 consultants and experts to conduct the disparity and
20 availability study, with the retention of those
21 consultants and experts exempt from the requirements
22 of Section 20-10 of the Illinois Procurement Code. The
23 Illinois Power Agency shall forward a copy of its
24 findings and recommendations to the Governor, the
25 General Assembly, and the Illinois Commerce
26 Commission. If the disparity and availability study

HB5856- 156 -LRB103 40655 LNS 73376 b
1 establishes a strong basis in evidence that there is
2 discrimination in Illinois' clean energy economy, the
3 Agency, Department of Commerce and Economic
4 Opportunity, Department of Labor, Department of
5 Corrections, and other appropriate agencies shall take
6 appropriate remedial actions, including race-conscious
7 remedial actions as consistent with State and federal
8 law, to effectively remedy this discrimination. Such
9 remedies may include modification of the equity
10 accountability system as described in subsection
11 (c-10).
12 (c-20) Program data collection.
13 (1) Purpose. Data collection, data analysis, and
14 reporting are critical to ensure that the benefits of the
15 clean energy economy provided to Illinois residents and
16 businesses are equitably distributed across the State. The
17 Agency shall collect data from program applicants in order
18 to track and improve equitable distribution of benefits
19 across Illinois communities for all procurements the
20 Agency conducts. The Agency shall use this data to, among
21 other things, measure any potential impact of racial
22 discrimination on the distribution of benefits and provide
23 information necessary to correct any discrimination
24 through methods consistent with State and federal law.
25 (2) Agency collection of program data. The Agency
26 shall collect demographic and geographic data for each

HB5856- 157 -LRB103 40655 LNS 73376 b
1 entity awarded contracts under any Agency-administered
2 program. The Agency shall collect this data on an annual
3 basis for all systems energized during the applicable
4 annual period, but shall allow entities awarded contracts
5 under any Agency-administered program to elect to report
6 data exclusively on a project-by-project basis.
7 (3) Required information to be collected. The Agency
8 shall collect the following information from applicants
9 and program participants where applicable:
10 (A) demographic information, including racial or
11 ethnic identity for real persons employed, contracted,
12 or subcontracted through the program and owners of
13 businesses or entities that apply to receive renewable
14 energy credits from the Agency;
15 (B) geographic location of the residency of real
16 persons employed, contracted, or subcontracted through
17 the program and geographic location of the
18 headquarters of the business or entity that applies to
19 receive renewable energy credits from the Agency; and
20 (C) any other information the Agency determines is
21 necessary for the purpose of achieving the purpose of
22 this subsection.
23 (4) Publication of collected information. The Agency
24 shall publish, at least annually, information on the
25 demographics of program participants on an aggregate
26 basis.

HB5856- 158 -LRB103 40655 LNS 73376 b
1 (5) Nothing in this subsection shall be interpreted to
2 limit the authority of the Agency, or other agency or
3 department of the State, to require or collect demographic
4 information from applicants of other State programs.
5 (c-25) Energy Workforce Equity Database.
6 (1) The Agency, in consultation with the Department of
7 Commerce and Economic Opportunity, shall create an Energy
8 Workforce Equity Database, and may contract with a third
9 party to do so ("database program administrator"). If the
10 Department decides to contract with a third party, that
11 third party shall be exempt from the requirements of
12 Section 20-10 of the Illinois Procurement Code. The Energy
13 Workforce Equity Database shall be a searchable database
14 of suppliers, vendors, and subcontractors for clean energy
15 industries that is:
16 (A) publicly accessible;
17 (B) easy for people to find and use;
18 (C) organized by company specialty or field;
19 (D) region-specific; and
20 (E) populated with information including, but not
21 limited to, contacts for suppliers, vendors, or
22 subcontractors who are minority and women-owned
23 business enterprise certified or who participate or
24 have participated in any of the programs described in
25 this Act.
26 (2) The Agency shall create an easily accessible,

HB5856- 159 -LRB103 40655 LNS 73376 b
1 public facing online tool using the database information
2 that includes, at a minimum, the following:
3 (A) a map of environmental justice and equity
4 investment eligible communities;
5 (B) job postings and recruiting opportunities;
6 (C) a means by which recruiting clean energy
7 companies can find and interact with current or former
8 participants of clean energy workforce training
9 programs;
10 (D) information on workforce training service
11 providers and training opportunities available to
12 prospective workers;
13 (E) renewable energy company diversity reporting;
14 (F) a list of equity eligible contractors with
15 their contact information, types of work performed,
16 and locations worked in;
17 (G) reporting on outcomes of the programs
18 described in the workforce programs of the Energy
19 Transition Act, including information such as, but not
20 limited to, retention rate, graduation rate, and
21 placement rates of trainees; and
22 (H) information about the Jobs and Environmental
23 Justice Grant Program, the Clean Energy Jobs and
24 Justice Fund, and other sources of capital.
25 (3) The Agency shall ensure the database is regularly
26 updated to ensure information is current and shall

HB5856- 160 -LRB103 40655 LNS 73376 b
1 coordinate with the Department of Commerce and Economic
2 Opportunity to ensure that it includes information on
3 individuals and entities that are or have participated in
4 the Clean Jobs Workforce Network Program, Clean Energy
5 Contractor Incubator Program, Returning Residents Clean
6 Jobs Training Program, or Clean Energy Primes Contractor
7 Accelerator Program.
8 (c-30) Enforcement of minimum equity standards. All
9entities seeking renewable energy credits must submit an
10annual report to demonstrate compliance with each of the
11equity commitments required under subsection (c-10). If the
12Agency concludes the entity has not met or maintained its
13minimum equity standards required under the applicable
14subparagraphs under subsection (c-10), the Agency shall deny
15the entity's ability to participate in procurement programs in
16subsection (c), including by withholding approved vendor or
17designee status. The Agency may require the entity to enter
18into a corrective action plan. An entity that is not
19recertified for failing to meet required equity actions in
20subparagraph (c-10) may reapply once they have a corrective
21action plan and achieve compliance with the minimum equity
22standards.
23 (d) Clean coal portfolio standard.
24 (1) The procurement plans shall include electricity
25 generated using clean coal. Each utility shall enter into
26 one or more sourcing agreements with the initial clean

HB5856- 161 -LRB103 40655 LNS 73376 b
1 coal facility, as provided in paragraph (3) of this
2 subsection (d), covering electricity generated by the
3 initial clean coal facility representing at least 5% of
4 each utility's total supply to serve the load of eligible
5 retail customers in 2015 and each year thereafter, as
6 described in paragraph (3) of this subsection (d), subject
7 to the limits specified in paragraph (2) of this
8 subsection (d). It is the goal of the State that by January
9 1, 2025, 25% of the electricity used in the State shall be
10 generated by cost-effective clean coal facilities. For
11 purposes of this subsection (d), "cost-effective" means
12 that the expenditures pursuant to such sourcing agreements
13 do not cause the limit stated in paragraph (2) of this
14 subsection (d) to be exceeded and do not exceed cost-based
15 benchmarks, which shall be developed to assess all
16 expenditures pursuant to such sourcing agreements covering
17 electricity generated by clean coal facilities, other than
18 the initial clean coal facility, 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.
22 A utility party to a sourcing agreement shall
23 immediately retire any emission credits that it receives
24 in connection with the electricity covered by such
25 agreement.
26 Utilities shall maintain adequate records documenting

HB5856- 162 -LRB103 40655 LNS 73376 b
1 the purchases under the sourcing agreement to comply with
2 this subsection (d) and shall file an accounting with the
3 load forecast that must be filed with the Agency by July 15
4 of each year, in accordance with subsection (d) of Section
5 16-111.5 of the Public Utilities Act.
6 A utility shall be deemed to have complied with the
7 clean coal portfolio standard specified in this subsection
8 (d) if the utility enters into a sourcing agreement as
9 required by this subsection (d).
10 (2) For purposes of this subsection (d), the required
11 execution of sourcing agreements with the initial clean
12 coal facility for a particular year shall be measured as a
13 percentage of the actual amount of electricity
14 (megawatt-hours) supplied by the electric utility to
15 eligible retail customers in the planning year ending
16 immediately prior to the agreement's execution. For
17 purposes of this subsection (d), the amount paid per
18 kilowatthour means the total amount paid for electric
19 service expressed on a per kilowatthour basis. For
20 purposes of this subsection (d), the total amount paid for
21 electric service includes without limitation amounts paid
22 for supply, transmission, distribution, surcharges and
23 add-on taxes.
24 Notwithstanding the requirements of this subsection
25 (d), the total amount paid under sourcing agreements with
26 clean coal facilities pursuant to the procurement plan for

HB5856- 163 -LRB103 40655 LNS 73376 b
1 any given year shall be reduced by an amount necessary to
2 limit the annual estimated average net increase due to the
3 costs of these resources included in the amounts paid by
4 eligible retail customers in connection with electric
5 service to:
6 (A) in 2010, no more than 0.5% of the amount paid
7 per kilowatthour by those customers during the year
8 ending May 31, 2009;
9 (B) in 2011, the greater of an additional 0.5% of
10 the amount paid per kilowatthour by those customers
11 during the year ending May 31, 2010 or 1% of the amount
12 paid per kilowatthour by those customers during the
13 year ending May 31, 2009;
14 (C) in 2012, the greater of an additional 0.5% of
15 the amount paid per kilowatthour by those customers
16 during the year ending May 31, 2011 or 1.5% of the
17 amount paid per kilowatthour by those customers during
18 the year ending May 31, 2009;
19 (D) in 2013, the greater of an additional 0.5% of
20 the amount paid per kilowatthour by those customers
21 during the year ending May 31, 2012 or 2% of the amount
22 paid per kilowatthour by those customers during the
23 year ending May 31, 2009; and
24 (E) thereafter, the total amount paid under
25 sourcing agreements with clean coal facilities
26 pursuant to the procurement plan for any single year

HB5856- 164 -LRB103 40655 LNS 73376 b
1 shall be reduced by an amount necessary to limit the
2 estimated average net increase due to the cost of
3 these resources included in the amounts paid by
4 eligible retail customers in connection with electric
5 service to no more than the greater of (i) 2.015% of
6 the amount paid per kilowatthour by those customers
7 during the year ending May 31, 2009 or (ii) the
8 incremental amount per kilowatthour paid for these
9 resources in 2013. These requirements may be altered
10 only as provided by statute.
11 No later than June 30, 2015, the Commission shall
12 review the limitation on the total amount paid under
13 sourcing agreements, if any, with clean coal facilities
14 pursuant to this subsection (d) and report to the General
15 Assembly its findings as to whether that limitation unduly
16 constrains the amount of electricity generated by
17 cost-effective clean coal facilities that is covered by
18 sourcing agreements.
19 (3) Initial clean coal facility. In order to promote
20 development of clean coal facilities in Illinois, each
21 electric utility subject to this Section shall execute a
22 sourcing agreement to source electricity from a proposed
23 clean coal facility in Illinois (the "initial clean coal
24 facility") that will have a nameplate capacity of at least
25 500 MW when commercial operation commences, that has a
26 final Clean Air Act permit on June 1, 2009 (the effective

HB5856- 165 -LRB103 40655 LNS 73376 b
1 date of Public Act 95-1027), and that will meet the
2 definition of clean coal facility in Section 1-10 of this
3 Act when commercial operation commences. The sourcing
4 agreements with this initial clean coal facility shall be
5 subject to both approval of the initial clean coal
6 facility by the General Assembly and satisfaction of the
7 requirements of paragraph (4) of this subsection (d) and
8 shall be executed within 90 days after any such approval
9 by the General Assembly. The Agency and the Commission
10 shall have authority to inspect all books and records
11 associated with the initial clean coal facility during the
12 term of such a sourcing agreement. A utility's sourcing
13 agreement for electricity produced by the initial clean
14 coal facility shall include:
15 (A) a formula contractual price (the "contract
16 price") approved pursuant to paragraph (4) of this
17 subsection (d), which shall:
18 (i) be determined using a cost of service
19 methodology employing either a level or deferred
20 capital recovery component, based on a capital
21 structure consisting of 45% equity and 55% debt,
22 and a return on equity as may be approved by the
23 Federal Energy Regulatory Commission, which in any
24 case may not exceed the lower of 11.5% or the rate
25 of return approved by the General Assembly
26 pursuant to paragraph (4) of this subsection (d);

HB5856- 166 -LRB103 40655 LNS 73376 b
1 and
2 (ii) provide that all miscellaneous net
3 revenue, including but not limited to net revenue
4 from the sale of emission allowances, if any,
5 substitute natural gas, if any, grants or other
6 support provided by the State of Illinois or the
7 United States Government, firm transmission
8 rights, if any, by-products produced by the
9 facility, energy or capacity derived from the
10 facility and not covered by a sourcing agreement
11 pursuant to paragraph (3) of this subsection (d)
12 or item (5) of subsection (d) of Section 16-115 of
13 the Public Utilities Act, whether generated from
14 the synthesis gas derived from coal, from SNG, or
15 from natural gas, shall be credited against the
16 revenue requirement for this initial clean coal
17 facility;
18 (B) power purchase provisions, which shall:
19 (i) provide that the utility party to such
20 sourcing agreement shall pay the contract price
21 for electricity delivered under such sourcing
22 agreement;
23 (ii) require delivery of electricity to the
24 regional transmission organization market of the
25 utility that is party to such sourcing agreement;
26 (iii) require the utility party to such

HB5856- 167 -LRB103 40655 LNS 73376 b
1 sourcing agreement to buy from the initial clean
2 coal facility in each hour an amount of energy
3 equal to all clean coal energy made available from
4 the initial clean coal facility during such hour
5 times a fraction, the numerator of which is such
6 utility's retail market sales of electricity
7 (expressed in kilowatthours sold) in the State
8 during the prior calendar month and the
9 denominator of which is the total retail market
10 sales of electricity (expressed in kilowatthours
11 sold) in the State by utilities during such prior
12 month and the sales of electricity (expressed in
13 kilowatthours sold) in the State by alternative
14 retail electric suppliers during such prior month
15 that are subject to the requirements of this
16 subsection (d) and paragraph (5) of subsection (d)
17 of Section 16-115 of the Public Utilities Act,
18 provided that the amount purchased by the utility
19 in any year will be limited by paragraph (2) of
20 this subsection (d); and
21 (iv) be considered pre-existing contracts in
22 such utility's procurement plans for eligible
23 retail customers;
24 (C) contract for differences provisions, which
25 shall:
26 (i) require the utility party to such sourcing

HB5856- 168 -LRB103 40655 LNS 73376 b
1 agreement to contract with the initial clean coal
2 facility in each hour with respect to an amount of
3 energy equal to all clean coal energy made
4 available from the initial clean coal facility
5 during such hour times a fraction, the numerator
6 of which is such utility's retail market sales of
7 electricity (expressed in kilowatthours sold) in
8 the utility's service territory in the State
9 during the prior calendar month and the
10 denominator of which is the total retail market
11 sales of electricity (expressed in kilowatthours
12 sold) in the State by utilities during such prior
13 month and the sales of electricity (expressed in
14 kilowatthours sold) in the State by alternative
15 retail electric suppliers during such prior month
16 that are subject to the requirements of this
17 subsection (d) and paragraph (5) of subsection (d)
18 of Section 16-115 of the Public Utilities Act,
19 provided that the amount paid by the utility in
20 any year will be limited by paragraph (2) of this
21 subsection (d);
22 (ii) provide that the utility's payment
23 obligation in respect of the quantity of
24 electricity determined pursuant to the preceding
25 clause (i) shall be limited to an amount equal to
26 (1) the difference between the contract price

HB5856- 169 -LRB103 40655 LNS 73376 b
1 determined pursuant to subparagraph (A) of
2 paragraph (3) of this subsection (d) and the
3 day-ahead price for electricity delivered to the
4 regional transmission organization market of the
5 utility that is party to such sourcing agreement
6 (or any successor delivery point at which such
7 utility's supply obligations are financially
8 settled on an hourly basis) (the "reference
9 price") on the day preceding the day on which the
10 electricity is delivered to the initial clean coal
11 facility busbar, multiplied by (2) the quantity of
12 electricity determined pursuant to the preceding
13 clause (i); and
14 (iii) not require the utility to take physical
15 delivery of the electricity produced by the
16 facility;
17 (D) general provisions, which shall:
18 (i) specify a term of no more than 30 years,
19 commencing on the commercial operation date of the
20 facility;
21 (ii) provide that utilities shall maintain
22 adequate records documenting purchases under the
23 sourcing agreements entered into to comply with
24 this subsection (d) and shall file an accounting
25 with the load forecast that must be filed with the
26 Agency by July 15 of each year, in accordance with

HB5856- 170 -LRB103 40655 LNS 73376 b
1 subsection (d) of Section 16-111.5 of the Public
2 Utilities Act;
3 (iii) provide that all costs associated with
4 the initial clean coal facility will be
5 periodically reported to the Federal Energy
6 Regulatory Commission and to purchasers in
7 accordance with applicable laws governing
8 cost-based wholesale power contracts;
9 (iv) permit the Illinois Power Agency to
10 assume ownership of the initial clean coal
11 facility, without monetary consideration and
12 otherwise on reasonable terms acceptable to the
13 Agency, if the Agency so requests no less than 3
14 years prior to the end of the stated contract
15 term;
16 (v) require the owner of the initial clean
17 coal facility to provide documentation to the
18 Commission each year, starting in the facility's
19 first year of commercial operation, accurately
20 reporting the quantity of carbon emissions from
21 the facility that have been captured and
22 sequestered and report any quantities of carbon
23 released from the site or sites at which carbon
24 emissions were sequestered in prior years, based
25 on continuous monitoring of such sites. If, in any
26 year after the first year of commercial operation,

HB5856- 171 -LRB103 40655 LNS 73376 b
1 the owner of the facility fails to demonstrate
2 that the initial clean coal facility captured and
3 sequestered at least 50% of the total carbon
4 emissions that the facility would otherwise emit
5 or that sequestration of emissions from prior
6 years has failed, resulting in the release of
7 carbon dioxide into the atmosphere, the owner of
8 the facility must offset excess emissions. Any
9 such carbon offsets must be permanent, additional,
10 verifiable, real, located within the State of
11 Illinois, and legally and practicably enforceable.
12 The cost of such offsets for the facility that are
13 not recoverable shall not exceed $15 million in
14 any given year. No costs of any such purchases of
15 carbon offsets may be recovered from a utility or
16 its customers. All carbon offsets purchased for
17 this purpose and any carbon emission credits
18 associated with sequestration of carbon from the
19 facility must be permanently retired. The initial
20 clean coal facility shall not forfeit its
21 designation as a clean coal facility if the
22 facility fails to fully comply with the applicable
23 carbon sequestration requirements in any given
24 year, provided the requisite offsets are
25 purchased. However, the Attorney General, on
26 behalf of the People of the State of Illinois, may

HB5856- 172 -LRB103 40655 LNS 73376 b
1 specifically enforce the facility's sequestration
2 requirement and the other terms of this contract
3 provision. Compliance with the sequestration
4 requirements and offset purchase requirements
5 specified in paragraph (3) of this subsection (d)
6 shall be reviewed annually by an independent
7 expert retained by the owner of the initial clean
8 coal facility, with the advance written approval
9 of the Attorney General. The Commission may, in
10 the course of the review specified in item (vii),
11 reduce the allowable return on equity for the
12 facility if the facility willfully fails to comply
13 with the carbon capture and sequestration
14 requirements set forth in this item (v);
15 (vi) include limits on, and accordingly
16 provide for modification of, the amount the
17 utility is required to source under the sourcing
18 agreement consistent with paragraph (2) of this
19 subsection (d);
20 (vii) require Commission review: (1) to
21 determine the justness, reasonableness, and
22 prudence of the inputs to the formula referenced
23 in subparagraphs (A)(i) through (A)(iii) of
24 paragraph (3) of this subsection (d), prior to an
25 adjustment in those inputs including, without
26 limitation, the capital structure and return on

HB5856- 173 -LRB103 40655 LNS 73376 b
1 equity, fuel costs, and other operations and
2 maintenance costs and (2) to approve the costs to
3 be passed through to customers under the sourcing
4 agreement by which the utility satisfies its
5 statutory obligations. Commission review shall
6 occur no less than every 3 years, regardless of
7 whether any adjustments have been proposed, and
8 shall be completed within 9 months;
9 (viii) limit the utility's obligation to such
10 amount as the utility is allowed to recover
11 through tariffs filed with the Commission,
12 provided that neither the clean coal facility nor
13 the utility waives any right to assert federal
14 pre-emption or any other argument in response to a
15 purported disallowance of recovery costs;
16 (ix) limit the utility's or alternative retail
17 electric supplier's obligation to incur any
18 liability until such time as the facility is in
19 commercial operation and generating power and
20 energy and such power and energy is being
21 delivered to the facility busbar;
22 (x) provide that the owner or owners of the
23 initial clean coal facility, which is the
24 counterparty to such sourcing agreement, shall
25 have the right from time to time to elect whether
26 the obligations of the utility party thereto shall

HB5856- 174 -LRB103 40655 LNS 73376 b
1 be governed by the power purchase provisions or
2 the contract for differences provisions;
3 (xi) append documentation showing that the
4 formula rate and contract, insofar as they relate
5 to the power purchase provisions, have been
6 approved by the Federal Energy Regulatory
7 Commission pursuant to Section 205 of the Federal
8 Power Act;
9 (xii) provide that any changes to the terms of
10 the contract, insofar as such changes relate to
11 the power purchase provisions, are subject to
12 review under the public interest standard applied
13 by the Federal Energy Regulatory Commission
14 pursuant to Sections 205 and 206 of the Federal
15 Power Act; and
16 (xiii) conform with customary lender
17 requirements in power purchase agreements used as
18 the basis for financing non-utility generators.
19 (4) Effective date of sourcing agreements with the
20 initial clean coal facility. Any proposed sourcing
21 agreement with the initial clean coal facility shall not
22 become effective unless the following reports are prepared
23 and submitted and authorizations and approvals obtained:
24 (i) Facility cost report. The owner of the initial
25 clean coal facility shall submit to the Commission,
26 the Agency, and the General Assembly a front-end

HB5856- 175 -LRB103 40655 LNS 73376 b
1 engineering and design study, a facility cost report,
2 method of financing (including but not limited to
3 structure and associated costs), and an operating and
4 maintenance cost quote for the facility (collectively
5 "facility cost report"), which shall be prepared in
6 accordance with the requirements of this paragraph (4)
7 of subsection (d) of this Section, and shall provide
8 the Commission and the Agency access to the work
9 papers, relied upon documents, and any other backup
10 documentation related to the facility cost report.
11 (ii) Commission report. Within 6 months following
12 receipt of the facility cost report, the Commission,
13 in consultation with the Agency, shall submit a report
14 to the General Assembly setting forth its analysis of
15 the facility cost report. Such report shall include,
16 but not be limited to, a comparison of the costs
17 associated with electricity generated by the initial
18 clean coal facility to the costs associated with
19 electricity generated by other types of generation
20 facilities, an analysis of the rate impacts on
21 residential and small business customers over the life
22 of the sourcing agreements, and an analysis of the
23 likelihood that the initial clean coal facility will
24 commence commercial operation by and be delivering
25 power to the facility's busbar by 2016. To assist in
26 the preparation of its report, the Commission, in

HB5856- 176 -LRB103 40655 LNS 73376 b
1 consultation with the Agency, may hire one or more
2 experts or consultants, the costs of which shall be
3 paid for by the owner of the initial clean coal
4 facility. The Commission and Agency may begin the
5 process of selecting such experts or consultants prior
6 to receipt of the facility cost report.
7 (iii) General Assembly approval. The proposed
8 sourcing agreements shall not take effect unless,
9 based on the facility cost report and the Commission's
10 report, the General Assembly enacts authorizing
11 legislation approving (A) the projected price, stated
12 in cents per kilowatthour, to be charged for
13 electricity generated by the initial clean coal
14 facility, (B) the projected impact on residential and
15 small business customers' bills over the life of the
16 sourcing agreements, and (C) the maximum allowable
17 return on equity for the project; and
18 (iv) Commission review. If the General Assembly
19 enacts authorizing legislation pursuant to
20 subparagraph (iii) approving a sourcing agreement, the
21 Commission shall, within 90 days of such enactment,
22 complete a review of such sourcing agreement. During
23 such time period, the Commission shall implement any
24 directive of the General Assembly, resolve any
25 disputes between the parties to the sourcing agreement
26 concerning the terms of such agreement, approve the

HB5856- 177 -LRB103 40655 LNS 73376 b
1 form of such agreement, and issue an order finding
2 that the sourcing agreement is prudent and reasonable.
3 The facility cost report shall be prepared as follows:
4 (A) The facility cost report shall be prepared by
5 duly licensed engineering and construction firms
6 detailing the estimated capital costs payable to one
7 or more contractors or suppliers for the engineering,
8 procurement and construction of the components
9 comprising the initial clean coal facility and the
10 estimated costs of operation and maintenance of the
11 facility. The facility cost report shall include:
12 (i) an estimate of the capital cost of the
13 core plant based on one or more front end
14 engineering and design studies for the
15 gasification island and related facilities. The
16 core plant shall include all civil, structural,
17 mechanical, electrical, control, and safety
18 systems.
19 (ii) an estimate of the capital cost of the
20 balance of the plant, including any capital costs
21 associated with sequestration of carbon dioxide
22 emissions and all interconnects and interfaces
23 required to operate the facility, such as
24 transmission of electricity, construction or
25 backfeed power supply, pipelines to transport
26 substitute natural gas or carbon dioxide, potable

HB5856- 178 -LRB103 40655 LNS 73376 b
1 water supply, natural gas supply, water supply,
2 water discharge, landfill, access roads, and coal
3 delivery.
4 The quoted construction costs shall be expressed
5 in nominal dollars as of the date that the quote is
6 prepared and shall include capitalized financing costs
7 during construction, taxes, insurance, and other
8 owner's costs, and an assumed escalation in materials
9 and labor beyond the date as of which the construction
10 cost quote is expressed.
11 (B) The front end engineering and design study for
12 the gasification island and the cost study for the
13 balance of plant shall include sufficient design work
14 to permit quantification of major categories of
15 materials, commodities and labor hours, and receipt of
16 quotes from vendors of major equipment required to
17 construct and operate the clean coal facility.
18 (C) The facility cost report shall also include an
19 operating and maintenance cost quote that will provide
20 the estimated cost of delivered fuel, personnel,
21 maintenance contracts, chemicals, catalysts,
22 consumables, spares, and other fixed and variable
23 operations and maintenance costs. The delivered fuel
24 cost estimate will be provided by a recognized third
25 party expert or experts in the fuel and transportation
26 industries. The balance of the operating and

HB5856- 179 -LRB103 40655 LNS 73376 b
1 maintenance cost quote, excluding delivered fuel
2 costs, will be developed based on the inputs provided
3 by duly licensed engineering and construction firms
4 performing the construction cost quote, potential
5 vendors under long-term service agreements and plant
6 operating agreements, or recognized third party plant
7 operator or operators.
8 The operating and maintenance cost quote
9 (including the cost of the front end engineering and
10 design study) shall be expressed in nominal dollars as
11 of the date that the quote is prepared and shall
12 include taxes, insurance, and other owner's costs, and
13 an assumed escalation in materials and labor beyond
14 the date as of which the operating and maintenance
15 cost quote is expressed.
16 (D) The facility cost report shall also include an
17 analysis of the initial clean coal facility's ability
18 to deliver power and energy into the applicable
19 regional transmission organization markets and an
20 analysis of the expected capacity factor for the
21 initial clean coal facility.
22 (E) Amounts paid to third parties unrelated to the
23 owner or owners of the initial clean coal facility to
24 prepare the core plant construction cost quote,
25 including the front end engineering and design study,
26 and the operating and maintenance cost quote will be

HB5856- 180 -LRB103 40655 LNS 73376 b
1 reimbursed through Coal Development Bonds.
2 (5) Re-powering and retrofitting coal-fired power
3 plants previously owned by Illinois utilities to qualify
4 as clean coal facilities. During the 2009 procurement
5 planning process and thereafter, the Agency and the
6 Commission shall consider sourcing agreements covering
7 electricity generated by power plants that were previously
8 owned by Illinois utilities and that have been or will be
9 converted into clean coal facilities, as defined by
10 Section 1-10 of this Act. Pursuant to such procurement
11 planning process, the owners of such facilities may
12 propose to the Agency sourcing agreements with utilities
13 and alternative retail electric suppliers required to
14 comply with subsection (d) of this Section and item (5) of
15 subsection (d) of Section 16-115 of the Public Utilities
16 Act, covering electricity generated by such facilities. In
17 the case of sourcing agreements that are power purchase
18 agreements, the contract price for electricity sales shall
19 be established on a cost of service basis. In the case of
20 sourcing agreements that are contracts for differences,
21 the contract price from which the reference price is
22 subtracted shall be established on a cost of service
23 basis. The Agency and the Commission may approve any such
24 utility sourcing agreements that do not exceed cost-based
25 benchmarks developed by the procurement administrator, in
26 consultation with the Commission staff, Agency staff and

HB5856- 181 -LRB103 40655 LNS 73376 b
1 the procurement monitor, subject to Commission review and
2 approval. The Commission shall have authority to inspect
3 all books and records associated with these clean coal
4 facilities during the term of any such contract.
5 (6) Costs incurred under this subsection (d) or
6 pursuant to a contract entered into under this subsection
7 (d) shall be deemed prudently incurred and reasonable in
8 amount and the electric utility shall be entitled to full
9 cost recovery pursuant to the tariffs filed with the
10 Commission.
11 (d-5) Zero emission standard.
12 (1) Beginning with the delivery year commencing on
13 June 1, 2017, the Agency shall, for electric utilities
14 that serve at least 100,000 retail customers in this
15 State, procure contracts with zero emission facilities
16 that are reasonably capable of generating cost-effective
17 zero emission credits in an amount approximately equal to
18 16% of the actual amount of electricity delivered by each
19 electric utility to retail customers in the State during
20 calendar year 2014. For an electric utility serving fewer
21 than 100,000 retail customers in this State that
22 requested, under Section 16-111.5 of the Public Utilities
23 Act, that the Agency procure power and energy for all or a
24 portion of the utility's Illinois load for the delivery
25 year commencing June 1, 2016, the Agency shall procure
26 contracts with zero emission facilities that are

HB5856- 182 -LRB103 40655 LNS 73376 b
1 reasonably capable of generating cost-effective zero
2 emission credits in an amount approximately equal to 16%
3 of the portion of power and energy to be procured by the
4 Agency for the utility. The duration of the contracts
5 procured under this subsection (d-5) shall be for a term
6 of 10 years ending May 31, 2027. The quantity of zero
7 emission credits to be procured under the contracts shall
8 be all of the zero emission credits generated by the zero
9 emission facility in each delivery year; however, if the
10 zero emission facility is owned by more than one entity,
11 then the quantity of zero emission credits to be procured
12 under the contracts shall be the amount of zero emission
13 credits that are generated from the portion of the zero
14 emission facility that is owned by the winning supplier.
15 The 16% value identified in this paragraph (1) is the
16 average of the percentage targets in subparagraph (B) of
17 paragraph (1) of subsection (c) of this Section for the 5
18 delivery years beginning June 1, 2017.
19 The procurement process shall be subject to the
20 following provisions:
21 (A) Those zero emission facilities that intend to
22 participate in the procurement shall submit to the
23 Agency the following eligibility information for each
24 zero emission facility on or before the date
25 established by the Agency:
26 (i) the in-service date and remaining useful

HB5856- 183 -LRB103 40655 LNS 73376 b
1 life of the zero emission facility;
2 (ii) the amount of power generated annually
3 for each of the years 2005 through 2015, and the
4 projected zero emission credits to be generated
5 over the remaining useful life of the zero
6 emission facility, which shall be used to
7 determine the capability of each facility;
8 (iii) the annual zero emission facility cost
9 projections, expressed on a per megawatt hour
10 megawatthour basis, over the next 6 delivery
11 years, which shall include the following:
12 operation and maintenance expenses; fully
13 allocated overhead costs, which shall be allocated
14 using the methodology developed by the Institute
15 for Nuclear Power Operations; fuel expenditures;
16 non-fuel capital expenditures; spent fuel
17 expenditures; a return on working capital; the
18 cost of operational and market risks that could be
19 avoided by ceasing operation; and any other costs
20 necessary for continued operations, provided that
21 "necessary" means, for purposes of this item
22 (iii), that the costs could reasonably be avoided
23 only by ceasing operations of the zero emission
24 facility; and
25 (iv) a commitment to continue operating, for
26 the duration of the contract or contracts executed

HB5856- 184 -LRB103 40655 LNS 73376 b
1 under the procurement held under this subsection
2 (d-5), the zero emission facility that produces
3 the zero emission credits to be procured in the
4 procurement.
5 The information described in item (iii) of this
6 subparagraph (A) may be submitted on a confidential
7 basis and shall be treated and maintained by the
8 Agency, the procurement administrator, and the
9 Commission as confidential and proprietary and exempt
10 from disclosure under subparagraphs (a) and (g) of
11 paragraph (1) of Section 7 of the Freedom of
12 Information Act. The Office of Attorney General shall
13 have access to, and maintain the confidentiality of,
14 such information pursuant to Section 6.5 of the
15 Attorney General Act.
16 (B) The price for each zero emission credit
17 procured under this subsection (d-5) for each delivery
18 year shall be in an amount that equals the Social Cost
19 of Carbon, expressed on a price per megawatt hour
20 megawatthour basis. However, to ensure that the
21 procurement remains affordable to retail customers in
22 this State if electricity prices increase, the price
23 in an applicable delivery year shall be reduced below
24 the Social Cost of Carbon by the amount ("Price
25 Adjustment") by which the market price index for the
26 applicable delivery year exceeds the baseline market

HB5856- 185 -LRB103 40655 LNS 73376 b
1 price index for the consecutive 12-month period ending
2 May 31, 2016. If the Price Adjustment is greater than
3 or equal to the Social Cost of Carbon in an applicable
4 delivery year, then no payments shall be due in that
5 delivery year. The components of this calculation are
6 defined as follows:
7 (i) Social Cost of Carbon: The Social Cost of
8 Carbon is $16.50 per megawatt hour megawatthour,
9 which is based on the U.S. Interagency Working
10 Group on Social Cost of Carbon's price in the
11 August 2016 Technical Update using a 3% discount
12 rate, adjusted for inflation for each year of the
13 program. Beginning with the delivery year
14 commencing June 1, 2023, the price per megawatt
15 hour megawatthour shall increase by $1 per
16 megawatt hour megawatthour, and continue to
17 increase by an additional $1 per megawatt hour
18 megawatthour each delivery year thereafter.
19 (ii) Baseline market price index: The baseline
20 market price index for the consecutive 12-month
21 period ending May 31, 2016 is $31.40 per megawatt
22 hour megawatthour, which is based on the sum of
23 (aa) the average day-ahead energy price across all
24 hours of such 12-month period at the PJM
25 Interconnection LLC Northern Illinois Hub, (bb)
26 50% multiplied by the Base Residual Auction, or

HB5856- 186 -LRB103 40655 LNS 73376 b
1 its successor, capacity price for the rest of the
2 RTO zone group determined by PJM Interconnection
3 LLC, divided by 24 hours per day, and (cc) 50%
4 multiplied by the Planning Resource Auction, or
5 its successor, capacity price for Zone 4
6 determined by the Midcontinent Independent System
7 Operator, Inc., divided by 24 hours per day.
8 (iii) Market price index: The market price
9 index for a delivery year shall be the sum of
10 projected energy prices and projected capacity
11 prices determined as follows:
12 (aa) Projected energy prices: the
13 projected energy prices for the applicable
14 delivery year shall be calculated once for the
15 year using the forward market price for the
16 PJM Interconnection, LLC Northern Illinois
17 Hub. The forward market price shall be
18 calculated as follows: the energy forward
19 prices for each month of the applicable
20 delivery year averaged for each trade date
21 during the calendar year immediately preceding
22 that delivery year to produce a single energy
23 forward price for the delivery year. The
24 forward market price calculation shall use
25 data published by the Intercontinental
26 Exchange, or its successor.

HB5856- 187 -LRB103 40655 LNS 73376 b
1 (bb) Projected capacity prices:
2 (I) For the delivery years commencing
3 June 1, 2017, June 1, 2018, and June 1,
4 2019, the projected capacity price shall
5 be equal to the sum of (1) 50% multiplied
6 by the Base Residual Auction, or its
7 successor, price for the rest of the RTO
8 zone group as determined by PJM
9 Interconnection LLC, divided by 24 hours
10 per day and, (2) 50% multiplied by the
11 resource auction price determined in the
12 resource auction administered by the
13 Midcontinent Independent System Operator,
14 Inc., in which the largest percentage of
15 load cleared for Local Resource Zone 4,
16 divided by 24 hours per day, and where
17 such price is determined by the
18 Midcontinent Independent System Operator,
19 Inc.
20 (II) For the delivery year commencing
21 June 1, 2020, and each year thereafter,
22 the projected capacity price shall be
23 equal to the sum of (1) 50% multiplied by
24 the Base Residual Auction, or its
25 successor, price for the ComEd zone as
26 determined by PJM Interconnection LLC,

HB5856- 188 -LRB103 40655 LNS 73376 b
1 divided by 24 hours per day, and (2) 50%
2 multiplied by the resource auction price
3 determined in the resource auction
4 administered by the Midcontinent
5 Independent System Operator, Inc., in
6 which the largest percentage of load
7 cleared for Local Resource Zone 4, divided
8 by 24 hours per day, and where such price
9 is determined by the Midcontinent
10 Independent System Operator, Inc.
11 For purposes of this subsection (d-5):
12 "Rest of the RTO" and "ComEd Zone" shall have
13 the meaning ascribed to them by PJM
14 Interconnection, LLC.
15 "RTO" means regional transmission
16 organization.
17 (C) No later than 45 days after June 1, 2017 (the
18 effective date of Public Act 99-906), the Agency shall
19 publish its proposed zero emission standard
20 procurement plan. The plan shall be consistent with
21 the provisions of this paragraph (1) and shall provide
22 that winning bids shall be selected based on public
23 interest criteria that include, but are not limited
24 to, minimizing carbon dioxide emissions that result
25 from electricity consumed in Illinois and minimizing
26 sulfur dioxide, nitrogen oxide, and particulate matter

HB5856- 189 -LRB103 40655 LNS 73376 b
1 emissions that adversely affect the citizens of this
2 State. In particular, the selection of winning bids
3 shall take into account the incremental environmental
4 benefits resulting from the procurement, such as any
5 existing environmental benefits that are preserved by
6 the procurements held under Public Act 99-906 and
7 would cease to exist if the procurements were not
8 held, including the preservation of zero emission
9 facilities. The plan shall also describe in detail how
10 each public interest factor shall be considered and
11 weighted in the bid selection process to ensure that
12 the public interest criteria are applied to the
13 procurement and given full effect.
14 For purposes of developing the plan, the Agency
15 shall consider any reports issued by a State agency,
16 board, or commission under House Resolution 1146 of
17 the 98th General Assembly and paragraph (4) of
18 subsection (d) of this Section, as well as publicly
19 available analyses and studies performed by or for
20 regional transmission organizations that serve the
21 State and their independent market monitors.
22 Upon publishing of the zero emission standard
23 procurement plan, copies of the plan shall be posted
24 and made publicly available on the Agency's website.
25 All interested parties shall have 10 days following
26 the date of posting to provide comment to the Agency on

HB5856- 190 -LRB103 40655 LNS 73376 b
1 the plan. All comments shall be posted to the Agency's
2 website. Following the end of the comment period, but
3 no more than 60 days later than June 1, 2017 (the
4 effective date of Public Act 99-906), the Agency shall
5 revise the plan as necessary based on the comments
6 received and file its zero emission standard
7 procurement plan with the Commission.
8 If the Commission determines that the plan will
9 result in the procurement of cost-effective zero
10 emission credits, then the Commission shall, after
11 notice and hearing, but no later than 45 days after the
12 Agency filed the plan, approve the plan or approve
13 with modification. For purposes of this subsection
14 (d-5), "cost effective" means the projected costs of
15 procuring zero emission credits from zero emission
16 facilities do not cause the limit stated in paragraph
17 (2) of this subsection to be exceeded.
18 (C-5) As part of the Commission's review and
19 acceptance or rejection of the procurement results,
20 the Commission shall, in its public notice of
21 successful bidders:
22 (i) identify how the winning bids satisfy the
23 public interest criteria described in subparagraph
24 (C) of this paragraph (1) of minimizing carbon
25 dioxide emissions that result from electricity
26 consumed in Illinois and minimizing sulfur

HB5856- 191 -LRB103 40655 LNS 73376 b
1 dioxide, nitrogen oxide, and particulate matter
2 emissions that adversely affect the citizens of
3 this State;
4 (ii) specifically address how the selection of
5 winning bids takes into account the incremental
6 environmental benefits resulting from the
7 procurement, including any existing environmental
8 benefits that are preserved by the procurements
9 held under Public Act 99-906 and would have ceased
10 to exist if the procurements had not been held,
11 such as the preservation of zero emission
12 facilities;
13 (iii) quantify the environmental benefit of
14 preserving the resources identified in item (ii)
15 of this subparagraph (C-5), including the
16 following:
17 (aa) the value of avoided greenhouse gas
18 emissions measured as the product of the zero
19 emission facilities' output over the contract
20 term multiplied by the U.S. Environmental
21 Protection Agency eGrid subregion carbon
22 dioxide emission rate and the U.S. Interagency
23 Working Group on Social Cost of Carbon's price
24 in the August 2016 Technical Update using a 3%
25 discount rate, adjusted for inflation for each
26 delivery year; and

HB5856- 192 -LRB103 40655 LNS 73376 b
1 (bb) the costs of replacement with other
2 zero carbon dioxide resources, including wind
3 and photovoltaic, based upon the simple
4 average of the following:
5 (I) the price, or if there is more
6 than one price, the average of the prices,
7 paid for renewable energy credits from new
8 utility-scale wind projects in the
9 procurement events specified in item (i)
10 of subparagraph (G) of paragraph (1) of
11 subsection (c) of this Section; and
12 (II) 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 solar projects and
16 brownfield site photovoltaic projects in
17 the procurement events specified in item
18 (ii) of subparagraph (G) of paragraph (1)
19 of subsection (c) of this Section and,
20 after January 1, 2015, renewable energy
21 credits from photovoltaic distributed
22 generation projects in procurement events
23 held under subsection (c) of this Section.
24 Each utility shall enter into binding contractual
25 arrangements with the winning suppliers.
26 The procurement described in this subsection

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1 (d-5), including, but not limited to, the execution of
2 all contracts procured, shall be completed no later
3 than May 10, 2017. Based on the effective date of
4 Public Act 99-906, the Agency and Commission may, as
5 appropriate, modify the various dates and timelines
6 under this subparagraph and subparagraphs (C) and (D)
7 of this paragraph (1). The procurement and plan
8 approval processes required by this subsection (d-5)
9 shall be conducted in conjunction with the procurement
10 and plan approval processes required by subsection (c)
11 of this Section and Section 16-111.5 of the Public
12 Utilities Act, to the extent practicable.
13 Notwithstanding whether a procurement event is
14 conducted under Section 16-111.5 of the Public
15 Utilities Act, the Agency shall immediately initiate a
16 procurement process on June 1, 2017 (the effective
17 date of Public Act 99-906).
18 (D) Following the procurement event described in
19 this paragraph (1) and consistent with subparagraph
20 (B) of this paragraph (1), the Agency shall calculate
21 the payments to be made under each contract for the
22 next delivery year based on the market price index for
23 that delivery year. The Agency shall publish the
24 payment calculations no later than May 25, 2017 and
25 every May 25 thereafter.
26 (E) Notwithstanding the requirements of this

HB5856- 194 -LRB103 40655 LNS 73376 b
1 subsection (d-5), the contracts executed under this
2 subsection (d-5) shall provide that the zero emission
3 facility may, as applicable, suspend or terminate
4 performance under the contracts in the following
5 instances:
6 (i) A zero emission facility shall be excused
7 from its performance under the contract for any
8 cause beyond the control of the resource,
9 including, but not restricted to, acts of God,
10 flood, drought, earthquake, storm, fire,
11 lightning, epidemic, war, riot, civil disturbance
12 or disobedience, labor dispute, labor or material
13 shortage, sabotage, acts of public enemy,
14 explosions, orders, regulations or restrictions
15 imposed by governmental, military, or lawfully
16 established civilian authorities, which, in any of
17 the foregoing cases, by exercise of commercially
18 reasonable efforts the zero emission facility
19 could not reasonably have been expected to avoid,
20 and which, by the exercise of commercially
21 reasonable efforts, it has been unable to
22 overcome. In such event, the zero emission
23 facility shall be excused from performance for the
24 duration of the event, including, but not limited
25 to, delivery of zero emission credits, and no
26 payment shall be due to the zero emission facility

HB5856- 195 -LRB103 40655 LNS 73376 b
1 during the duration of the event.
2 (ii) A zero emission facility shall be
3 permitted to terminate the contract if legislation
4 is enacted into law by the General Assembly that
5 imposes or authorizes a new tax, special
6 assessment, or fee on the generation of
7 electricity, the ownership or leasehold of a
8 generating unit, or the privilege or occupation of
9 such generation, ownership, or leasehold of
10 generation units by a zero emission facility.
11 However, the provisions of this item (ii) do not
12 apply to any generally applicable tax, special
13 assessment or fee, or requirements imposed by
14 federal law.
15 (iii) A zero emission facility shall be
16 permitted to terminate the contract in the event
17 that the resource requires capital expenditures in
18 excess of $40,000,000 that were neither known nor
19 reasonably foreseeable at the time it executed the
20 contract and that a prudent owner or operator of
21 such resource would not undertake.
22 (iv) A zero emission facility shall be
23 permitted to terminate the contract in the event
24 the Nuclear Regulatory Commission terminates the
25 resource's license.
26 (F) If the zero emission facility elects to

HB5856- 196 -LRB103 40655 LNS 73376 b
1 terminate a contract under subparagraph (E) of this
2 paragraph (1), then the Commission shall reopen the
3 docket in which the Commission approved the zero
4 emission standard procurement plan under subparagraph
5 (C) of this paragraph (1) and, after notice and
6 hearing, enter an order acknowledging the contract
7 termination election if such termination is consistent
8 with the provisions of this subsection (d-5).
9 (2) For purposes of this subsection (d-5), the amount
10 paid per kilowatthour means the total amount paid for
11 electric service expressed on a per kilowatthour basis.
12 For purposes of this subsection (d-5), the total amount
13 paid for electric service includes, without limitation,
14 amounts paid for supply, transmission, distribution,
15 surcharges, and add-on taxes.
16 Notwithstanding the requirements of this subsection
17 (d-5), the contracts executed under this subsection (d-5)
18 shall provide that the total of zero emission credits
19 procured under a procurement plan shall be subject to the
20 limitations of this paragraph (2). For each delivery year,
21 the contractual volume receiving payments in such year
22 shall be reduced for all retail customers based on the
23 amount necessary to limit the net increase that delivery
24 year to the costs of those credits included in the amounts
25 paid by eligible retail customers in connection with
26 electric service to no more than 1.65% of the amount paid

HB5856- 197 -LRB103 40655 LNS 73376 b
1 per kilowatthour by eligible retail customers during the
2 year ending May 31, 2009. The result of this computation
3 shall apply to and reduce the procurement for all retail
4 customers, and all those customers shall pay the same
5 single, uniform cents per kilowatthour charge under
6 subsection (k) of Section 16-108 of the Public Utilities
7 Act. To arrive at a maximum dollar amount of zero emission
8 credits to be paid for the particular delivery year, the
9 resulting per kilowatthour amount shall be applied to the
10 actual amount of kilowatthours of electricity delivered by
11 the electric utility in the delivery year immediately
12 prior to the procurement, to all retail customers in its
13 service territory. Unpaid contractual volume for any
14 delivery year shall be paid in any subsequent delivery
15 year in which such payments can be made without exceeding
16 the amount specified in this paragraph (2). The
17 calculations required by this paragraph (2) shall be made
18 only once for each procurement plan year. Once the
19 determination as to the amount of zero emission credits to
20 be paid is made based on the calculations set forth in this
21 paragraph (2), no subsequent rate impact determinations
22 shall be made and no adjustments to those contract amounts
23 shall be allowed. All costs incurred under those contracts
24 and in implementing this subsection (d-5) shall be
25 recovered by the electric utility as provided in this
26 Section.

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1 No later than June 30, 2019, the Commission shall
2 review the limitation on the amount of zero emission
3 credits procured under this subsection (d-5) and report to
4 the General Assembly its findings as to whether that
5 limitation unduly constrains the procurement of
6 cost-effective zero emission credits.
7 (3) Six years after the execution of a contract under
8 this subsection (d-5), the Agency shall determine whether
9 the actual zero emission credit payments received by the
10 supplier over the 6-year period exceed the Average ZEC
11 Payment. In addition, at the end of the term of a contract
12 executed under this subsection (d-5), or at the time, if
13 any, a zero emission facility's contract is terminated
14 under subparagraph (E) of paragraph (1) of this subsection
15 (d-5), then the Agency shall determine whether the actual
16 zero emission credit payments received by the supplier
17 over the term of the contract exceed the Average ZEC
18 Payment, after taking into account any amounts previously
19 credited back to the utility under this paragraph (3). If
20 the Agency determines that the actual zero emission credit
21 payments received by the supplier over the relevant period
22 exceed the Average ZEC Payment, then the supplier shall
23 credit the difference back to the utility. The amount of
24 the credit shall be remitted to the applicable electric
25 utility no later than 120 days after the Agency's
26 determination, which the utility shall reflect as a credit

HB5856- 199 -LRB103 40655 LNS 73376 b
1 on its retail customer bills as soon as practicable;
2 however, the credit remitted to the utility shall not
3 exceed the total amount of payments received by the
4 facility under its contract.
5 For purposes of this Section, the Average ZEC Payment
6 shall be calculated by multiplying the quantity of zero
7 emission credits delivered under the contract times the
8 average contract price. The average contract price shall
9 be determined by subtracting the amount calculated under
10 subparagraph (B) of this paragraph (3) from the amount
11 calculated under subparagraph (A) of this paragraph (3),
12 as follows:
13 (A) The average of the Social Cost of Carbon, as
14 defined in subparagraph (B) of paragraph (1) of this
15 subsection (d-5), during the term of the contract.
16 (B) The average of the market price indices, as
17 defined in subparagraph (B) of paragraph (1) of this
18 subsection (d-5), during the term of the contract,
19 minus the baseline market price index, as defined in
20 subparagraph (B) of paragraph (1) of this subsection
21 (d-5).
22 If the subtraction yields a negative number, then the
23 Average ZEC Payment shall be zero.
24 (4) Cost-effective zero emission credits procured from
25 zero emission facilities shall satisfy the applicable
26 definitions set forth in Section 1-10 of this Act.

HB5856- 200 -LRB103 40655 LNS 73376 b
1 (5) The electric utility shall retire all zero
2 emission credits used to comply with the requirements of
3 this subsection (d-5).
4 (6) Electric utilities shall be entitled to recover
5 all of the costs associated with the procurement of zero
6 emission credits through an automatic adjustment clause
7 tariff in accordance with subsection (k) and (m) of
8 Section 16-108 of the Public Utilities Act, and the
9 contracts executed under this subsection (d-5) shall
10 provide that the utilities' payment obligations under such
11 contracts shall be reduced if an adjustment is required
12 under subsection (m) of Section 16-108 of the Public
13 Utilities Act.
14 (7) This subsection (d-5) shall become inoperative on
15 January 1, 2028.
16 (d-10) Nuclear Plant Assistance; carbon mitigation
17credits.
18 (1) The General Assembly finds:
19 (A) The health, welfare, and prosperity of all
20 Illinois citizens require that the State of Illinois act
21 to avoid and not increase carbon emissions from electric
22 generation sources while continuing to ensure affordable,
23 stable, and reliable electricity to all citizens.
24 (B) Absent immediate action by the State to preserve
25 existing carbon-free energy resources, those resources may
26 retire, and the electric generation needs of Illinois'

HB5856- 201 -LRB103 40655 LNS 73376 b
1 retail customers may be met instead by facilities that
2 emit significant amounts of carbon pollution and other
3 harmful air pollutants at a high social and economic cost
4 until Illinois is able to develop other forms of clean
5 energy.
6 (C) The General Assembly finds that nuclear power
7 generation is necessary for the State's transition to 100%
8 clean energy, and ensuring continued operation of nuclear
9 plants advances environmental and public health interests
10 through providing carbon-free electricity while reducing
11 the air pollution profile of the Illinois energy
12 generation fleet.
13 (D) The clean energy attributes of nuclear generation
14 facilities support the State in its efforts to achieve
15 100% clean energy.
16 (E) The State currently invests in various forms of
17 clean energy, including, but not limited to, renewable
18 energy, energy efficiency, and low-emission vehicles,
19 among others.
20 (F) The Environmental Protection Agency commissioned
21 an independent audit which provided a detailed assessment
22 of the financial condition of the Illinois nuclear fleet
23 to evaluate its financial viability and whether the
24 environmental benefits of such resources were at risk. The
25 report identified the risk of losing the environmental
26 benefits of several specific nuclear units. The report

HB5856- 202 -LRB103 40655 LNS 73376 b
1 also identified that the LaSalle County Generating Station
2 will continue to operate through 2026 and therefore is not
3 eligible to participate in the carbon mitigation credit
4 program.
5 (G) Nuclear plants provide carbon-free energy, which
6 helps to avoid many health-related negative impacts for
7 Illinois residents.
8 (H) The procurement of carbon mitigation credits
9 representing the environmental benefits of carbon-free
10 generation will further the State's efforts at achieving
11 100% clean energy and decarbonizing the electricity sector
12 in a safe, reliable, and affordable manner. Further, the
13 procurement of carbon emission credits will enhance the
14 health and welfare of Illinois residents through decreased
15 reliance on more highly polluting generation.
16 (I) The General Assembly therefore finds it necessary
17 to establish carbon mitigation credits to ensure decreased
18 reliance on more carbon-intensive energy resources, for
19 transitioning to a fully decarbonized electricity sector,
20 and to help ensure health and welfare of the State's
21 residents.
22 (2) As used in this subsection:
23 "Baseline costs" means costs used to establish a customer
24protection cap that have been evaluated through an independent
25audit of a carbon-free energy resource conducted by the
26Environmental Protection Agency that evaluated projected

HB5856- 203 -LRB103 40655 LNS 73376 b
1annual costs for operation and maintenance expenses; fully
2allocated overhead costs, which shall be allocated using the
3methodology developed by the Institute for Nuclear Power
4Operations; fuel expenditures; nonfuel capital expenditures;
5spent fuel expenditures; a return on working capital; the cost
6of operational and market risks that could be avoided by
7ceasing operation; and any other costs necessary for continued
8operations, provided that "necessary" means, for purposes of
9this definition, that the costs could reasonably be avoided
10only by ceasing operations of the carbon-free energy resource.
11 "Carbon mitigation credit" means a tradable credit that
12represents the carbon emission reduction attributes of one
13megawatt-hour of energy produced from a carbon-free energy
14resource.
15 "Carbon-free energy resource" means a generation facility
16that: (1) is fueled by nuclear power; and (2) is
17interconnected to PJM Interconnection, LLC.
18 (3) Procurement.
19 (A) Beginning with the delivery year commencing on
20 June 1, 2022, the Agency shall, for electric utilities
21 serving at least 3,000,000 retail customers in the State,
22 seek to procure contracts for no more than approximately
23 54,500,000 cost-effective carbon mitigation credits from
24 carbon-free energy resources because such credits are
25 necessary to support current levels of carbon-free energy
26 generation and ensure the State meets its carbon dioxide

HB5856- 204 -LRB103 40655 LNS 73376 b
1 emissions reduction goals. The Agency shall not make a
2 partial award of a contract for carbon mitigation credits
3 covering a fractional amount of a carbon-free energy
4 resource's projected output.
5 (B) Each carbon-free energy resource that intends to
6 participate in a procurement shall be required to submit
7 to the Agency the following information for the resource
8 on or before the date established by the Agency:
9 (i) the in-service date and remaining useful life
10 of the carbon-free energy resource;
11 (ii) the amount of power generated annually for
12 each of the past 10 years, which shall be used to
13 determine the capability of each facility;
14 (iii) a commitment to be reflected in any contract
15 entered into pursuant to this subsection (d-10) to
16 continue operating the carbon-free energy resource at
17 a capacity factor of at least 88% annually on average
18 for the duration of the contract or contracts executed
19 under the procurement held under this subsection
20 (d-10), except in an instance described in
21 subparagraph (E) of paragraph (1) of subsection (d-5)
22 of this Section or made impracticable as a result of
23 compliance with law or regulation;
24 (iv) financial need and the risk of loss of the
25 environmental benefits of such resource, which shall
26 include the following information:

HB5856- 205 -LRB103 40655 LNS 73376 b
1 (I) the carbon-free energy resource's cost
2 projections, expressed on a per megawatt-hour
3 basis, over the next 5 delivery years, which shall
4 include the following: operation and maintenance
5 expenses; fully allocated overhead costs, which
6 shall be allocated using the methodology developed
7 by the Institute for Nuclear Power Operations;
8 fuel expenditures; nonfuel capital expenditures;
9 spent fuel expenditures; a return on working
10 capital; the cost of operational and market risks
11 that could be avoided by ceasing operation; and
12 any other costs necessary for continued
13 operations, provided that "necessary" means, for
14 purposes of this subitem (I), that the costs could
15 reasonably be avoided only by ceasing operations
16 of the carbon-free energy resource; and
17 (II) the carbon-free energy resource's revenue
18 projections, including energy, capacity, ancillary
19 services, any other direct State support, known or
20 anticipated federal attribute credits, known or
21 anticipated tax credits, and any other direct
22 federal support.
23 The information described in this subparagraph (B) may
24 be submitted on a confidential basis and shall be treated
25 and maintained by the Agency, the procurement
26 administrator, and the Commission as confidential and

HB5856- 206 -LRB103 40655 LNS 73376 b
1 proprietary and exempt from disclosure under subparagraphs
2 (a) and (g) of paragraph (1) of Section 7 of the Freedom of
3 Information Act. The Office of the Attorney General shall
4 have access to, and maintain the confidentiality of, such
5 information pursuant to Section 6.5 of the Attorney
6 General Act.
7 (C) The Agency shall solicit bids for the contracts
8 described in this subsection (d-10) from carbon-free
9 energy resources that have satisfied the requirements of
10 subparagraph (B) of this paragraph (3). The contracts
11 procured pursuant to a procurement event shall reflect,
12 and be subject to, the following terms, requirements, and
13 limitations:
14 (i) Contracts are for delivery of carbon
15 mitigation credits, and are not energy or capacity
16 sales contracts requiring physical delivery. Pursuant
17 to item (iii), contract payments shall fully deduct
18 the value of any monetized federal production tax
19 credits, credits issued pursuant to a federal clean
20 energy standard, and other federal credits if
21 applicable.
22 (ii) Contracts for carbon mitigation credits shall
23 commence with the delivery year beginning on June 1,
24 2022 and shall be for a term of 5 delivery years
25 concluding on May 31, 2027.
26 (iii) The price per carbon mitigation credit to be

HB5856- 207 -LRB103 40655 LNS 73376 b
1 paid under a contract for a given delivery year shall
2 be equal to an accepted bid price less the sum of:
3 (I) one of the following energy price indices,
4 selected by the bidder at the time of the bid for
5 the term of the contract:
6 (aa) the weighted-average hourly day-ahead
7 price for the applicable delivery year at the
8 busbar of all resources procured pursuant to
9 this subsection (d-10), weighted by actual
10 production from the resources; or
11 (bb) the projected energy price for the
12 PJM Interconnection, LLC Northern Illinois Hub
13 for the applicable delivery year determined
14 according to subitem (aa) of item (iii) of
15 subparagraph (B) of paragraph (1) of
16 subsection (d-5).
17 (II) the Base Residual Auction Capacity Price
18 for the ComEd zone as determined by PJM
19 Interconnection, LLC, divided by 24 hours per day,
20 for the applicable delivery year for the first 3
21 delivery years, and then any subsequent delivery
22 years unless the PJM Interconnection, LLC applies
23 the Minimum Offer Price Rule to participating
24 carbon-free energy resources because they supply
25 carbon mitigation credits pursuant to this Section
26 at which time, upon notice by the carbon-free

HB5856- 208 -LRB103 40655 LNS 73376 b
1 energy resource to the Commission and subject to
2 the Commission's confirmation, the value under
3 this subitem shall be zero, as further described
4 in the carbon mitigation credit procurement plan;
5 and
6 (III) any value of monetized federal tax
7 credits, direct payments, or similar subsidy
8 provided to the carbon-free energy resource from
9 any unit of government that is not already
10 reflected in energy prices.
11 If the price-per-megawatt-hour calculation
12 performed under item (iii) of this subparagraph (C)
13 for a given delivery year results in a net positive
14 value, then the electric utility counterparty to the
15 contract shall multiply such net value by the
16 applicable contract quantity and remit the amount to
17 the supplier.
18 To protect retail customers from retail rate
19 impacts that may arise upon the initiation of carbon
20 policy changes, if the price-per-megawatt-hour
21 calculation performed under item (iii) of this
22 subparagraph (C) for a given delivery year results in
23 a net negative value, then the supplier counterparty
24 to the contract shall multiply such net value by the
25 applicable contract quantity and remit such amount to
26 the electric utility counterparty. The electric

HB5856- 209 -LRB103 40655 LNS 73376 b
1 utility shall reflect such amounts remitted by
2 suppliers as a credit on its retail customer bills as
3 soon as practicable.
4 (iv) To ensure that retail customers in Northern
5 Illinois do not pay more for carbon mitigation credits
6 than the value such credits provide, and
7 notwithstanding the provisions of this subsection
8 (d-10), the Agency shall not accept bids for contracts
9 that exceed a customer protection cap equal to the
10 baseline costs of carbon-free energy resources.
11 The baseline costs for the applicable year shall
12 be the following:
13 (I) For the delivery year beginning June 1,
14 2022, the baseline costs shall be an amount equal
15 to $30.30 per megawatt-hour.
16 (II) For the delivery year beginning June 1,
17 2023, the baseline costs shall be an amount equal
18 to $32.50 per megawatt-hour.
19 (III) For the delivery year beginning June 1,
20 2024, the baseline costs shall be an amount equal
21 to $33.43 per megawatt-hour.
22 (IV) For the delivery year beginning June 1,
23 2025, the baseline costs shall be an amount equal
24 to $33.50 per megawatt-hour.
25 (V) For the delivery year beginning June 1,
26 2026, the baseline costs shall be an amount equal

HB5856- 210 -LRB103 40655 LNS 73376 b
1 to $34.50 per megawatt-hour.
2 An Environmental Protection Agency consultant
3 forecast, included in a report issued April 14, 2021,
4 projects that a carbon-free energy resource has the
5 opportunity to earn on average approximately $30.28
6 per megawatt-hour, for the sale of energy and capacity
7 during the time period between 2022 and 2027.
8 Therefore, the sale of carbon mitigation credits
9 provides the opportunity to receive an additional
10 amount per megawatt-hour in addition to the projected
11 prices for energy and capacity.
12 Although actual energy and capacity prices may
13 vary from year-to-year, the General Assembly finds
14 that this customer protection cap will help ensure
15 that the cost of carbon mitigation credits will be
16 less than its value, based upon the social cost of
17 carbon identified in the Technical Support Document
18 issued in February 2021 by the U.S. Interagency
19 Working Group on Social Cost of Greenhouse Gases and
20 the PJM Interconnection, LLC carbon dioxide marginal
21 emission rate for 2020, and that a carbon-free energy
22 resource receiving payment for carbon mitigation
23 credits receives no more than necessary to keep those
24 units in operation.
25 (D) No later than 7 days after the effective date of
26 this amendatory Act of the 102nd General Assembly, the

HB5856- 211 -LRB103 40655 LNS 73376 b
1 Agency shall publish its proposed carbon mitigation credit
2 procurement plan. The Plan shall provide that winning bids
3 shall be selected by taking into consideration which
4 resources best match public interest criteria that
5 include, but are not limited to, minimizing carbon dioxide
6 emissions that result from electricity consumed in
7 Illinois and minimizing sulfur dioxide, nitrogen oxide,
8 and particulate matter emissions that adversely affect the
9 citizens of this State. The selection of winning bids
10 shall also take into account the incremental environmental
11 benefits resulting from the procurement or procurements,
12 such as any existing environmental benefits that are
13 preserved by a procurement held under this subsection
14 (d-10) and would cease to exist if the procurement were
15 not held, including the preservation of carbon-free energy
16 resources. For those bidders having the same public
17 interest criteria score, the relative ranking of such
18 bidders shall be determined by price. The Plan shall
19 describe in detail how each public interest factor shall
20 be considered and weighted in the bid selection process to
21 ensure that the public interest criteria are applied to
22 the procurement. The Plan shall, to the extent practical
23 and permissible by federal law, ensure that successful
24 bidders make commercially reasonable efforts to apply for
25 federal tax credits, direct payments, or similar subsidy
26 programs that support carbon-free generation and for which

HB5856- 212 -LRB103 40655 LNS 73376 b
1 the successful bidder is eligible. Upon publishing of the
2 carbon mitigation credit procurement plan, copies of the
3 plan shall be posted and made publicly available on the
4 Agency's website. All interested parties shall have 7 days
5 following the date of posting to provide comment to the
6 Agency on the plan. All comments shall be posted to the
7 Agency's website. Following the end of the comment period,
8 but no more than 19 days later than the effective date of
9 this amendatory Act of the 102nd General Assembly, the
10 Agency shall revise the plan as necessary based on the
11 comments received and file its carbon mitigation credit
12 procurement plan with the Commission.
13 (E) If the Commission determines that the plan is
14 likely to result in the procurement of cost-effective
15 carbon mitigation credits, then the Commission shall,
16 after notice and hearing and opportunity for comment, but
17 no later than 42 days after the Agency filed the plan,
18 approve the plan or approve it with modification. For
19 purposes of this subsection (d-10), "cost-effective" means
20 carbon mitigation credits that are procured from
21 carbon-free energy resources at prices that are within the
22 limits specified in this paragraph (3). As part of the
23 Commission's review and acceptance or rejection of the
24 procurement results, the Commission shall, in its public
25 notice of successful bidders:
26 (i) identify how the selected carbon-free energy

HB5856- 213 -LRB103 40655 LNS 73376 b
1 resources satisfy the public interest criteria
2 described in this paragraph (3) of minimizing carbon
3 dioxide emissions that result from electricity
4 consumed in Illinois and minimizing sulfur dioxide,
5 nitrogen oxide, and particulate matter emissions that
6 adversely affect the citizens of this State;
7 (ii) specifically address how the selection of
8 carbon-free energy resources takes into account the
9 incremental environmental benefits resulting from the
10 procurement, including any existing environmental
11 benefits that are preserved by the procurements held
12 under this amendatory Act of the 102nd General
13 Assembly and would have ceased to exist if the
14 procurements had not been held, such as the
15 preservation of carbon-free energy resources;
16 (iii) quantify the environmental benefit of
17 preserving the carbon-free energy resources procured
18 pursuant to this subsection (d-10), including the
19 following:
20 (I) an assessment value of avoided greenhouse
21 gas emissions measured as the product of the
22 carbon-free energy resources' output over the
23 contract term, using generally accepted
24 methodologies for the valuation of avoided
25 emissions; and
26 (II) an assessment of costs of replacement

HB5856- 214 -LRB103 40655 LNS 73376 b
1 with other carbon-free energy resources and
2 renewable energy resources, including wind and
3 photovoltaic generation, based upon an assessment
4 of the prices paid for renewable energy credits
5 through programs and procurements conducted
6 pursuant to subsection (c) of Section 1-75 of this
7 Act, and the additional storage necessary to
8 produce the same or similar capability of matching
9 customer usage patterns.
10 (F) The procurements described in this paragraph (3),
11 including, but not limited to, the execution of all
12 contracts procured, shall be completed no later than
13 December 3, 2021. The procurement and plan approval
14 processes required by this paragraph (3) shall be
15 conducted in conjunction with the procurement and plan
16 approval processes required by Section 16-111.5 of the
17 Public Utilities Act, to the extent practicable. However,
18 the Agency and Commission may, as appropriate, modify the
19 various dates and timelines under this subparagraph and
20 subparagraphs (D) and (E) of this paragraph (3) to meet
21 the December 3, 2021 contract execution deadline.
22 Following the completion of such procurements, and
23 consistent with this paragraph (3), the Agency shall
24 calculate the payments to be made under each contract in a
25 timely fashion.
26 (F-1) Costs incurred by the electric utility pursuant

HB5856- 215 -LRB103 40655 LNS 73376 b
1 to a contract authorized by this subsection (d-10) shall
2 be deemed prudently incurred and reasonable in amount, and
3 the electric utility shall be entitled to full cost
4 recovery pursuant to a tariff or tariffs filed with the
5 Commission.
6 (G) The counterparty electric utility shall retire all
7 carbon mitigation credits used to comply with the
8 requirements of this subsection (d-10).
9 (H) If a carbon-free energy resource is sold to
10 another owner, the rights, obligations, and commitments
11 under this subsection (d-10) shall continue to the
12 subsequent owner.
13 (I) This subsection (d-10) shall become inoperative on
14 January 1, 2028.
15 (e) The draft procurement plans are subject to public
16comment, as required by Section 16-111.5 of the Public
17Utilities Act.
18 (f) The Agency shall submit the final procurement plan to
19the Commission. The Agency shall revise a procurement plan if
20the Commission determines that it does not meet the standards
21set forth in Section 16-111.5 of the Public Utilities Act.
22 (g) The Agency shall assess fees to each affected utility
23to recover the costs incurred in preparation of the annual
24procurement plan for the utility.
25 (h) The Agency shall assess fees to each bidder to recover
26the costs incurred in connection with a competitive

HB5856- 216 -LRB103 40655 LNS 73376 b
1procurement process.
2 (i) A renewable energy credit, carbon emission credit,
3zero emission credit, or carbon mitigation credit can only be
4used once to comply with a single portfolio or other standard
5as set forth in subsection (c), subsection (d), or subsection
6(d-5) of this Section, respectively. A renewable energy
7credit, carbon emission credit, zero emission credit, or
8carbon mitigation credit cannot be used to satisfy the
9requirements of more than one standard. If more than one type
10of credit is issued for the same megawatt hour of energy, only
11one credit can be used to satisfy the requirements of a single
12standard. After such use, the credit must be retired together
13with any other credits issued for the same megawatt hour of
14energy.
15(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24;
16103-580, eff. 12-8-23.)
17 (20 ILCS 3855/1-93 new)
18 Sec. 1-93. Energy storage credit targets.
19 (a) The Agency shall develop a storage procurement plan
20that results in electric utilities contracting for energy
21storage credits from contracted energy storage systems in the
22following amounts:
23 (1) at least 1,000 megawatts of cumulative energy
24 storage capacity by the end of delivery year 2024, of
25 which 200 megawatts are to be procured using indexed

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1 credits, 200 megawatts are to be procured using tolling
2 agreements, and 600 megawatts are to be procured using
3 either indexed credits or tolling agreements in the
4 discretion of the Agency;
5 (2) at least 3,000 megawatts of cumulative energy
6 storage capacity by delivery year 2026, with the
7 additional 2,000 megawatts split as follows: 400 megawatts
8 are to be procured using indexed credits, 400 megawatts
9 are to be procured using tolling agreements, and 1,200
10 megawatts are to be procured using either indexed credits
11 or tolling agreements as approved in the long-term
12 procurement plan;
13 (3) at least 5,000 megawatts of cumulative energy
14 storage capacity by delivery year 2028 with the additional
15 2,000 megawatts split as follows: 400 megawatts are to be
16 procured using indexed credits, 400 megawatts are to be
17 procured using tolling agreements, and 1,200 megawatts are
18 to be procured using either indexed credits or tolling
19 agreements as approved in the long-term procurement plan;
20 and
21 (4) at least 7,500 megawatts of cumulative energy
22 storage capacity by delivery year 2030 with the additional
23 2,500 megawatts split as follows: 500 megawatts are to be
24 procured using indexed credits, 500 megawatts are to be
25 procured using tolling agreements, and 1,200 megawatts are
26 to be procured using either indexed credits or tolling

HB5856- 218 -LRB103 40655 LNS 73376 b
1 agreements as approved in the long-term procurement plan.
2 (b) Within 180 days after the effective date of this
3amendatory Act of the 103rd General Assembly, the Agency shall
4develop an energy storage procurement plan in accordance with
5this Section and Section 16-111.5 of the Public Utilities Act.
6 (c) For procurements of energy storage credits, the Agency
7shall procure energy storage credits using methodologies
8including, but not limited to, tolling agreements and indexed
9energy storage credits. The Agency shall select bids based on
10the bid price when compared with equal energy storage duration
11and interconnected to the same independent system operator or
12regional transmission organization, and may give consideration
13to project viability and developer experience. The
14procurements of energy storage credits under this subsection
15shall be made as follows:
16 (1) For indexed energy storage credit procurements,
17 the purchase price of the indexed energy storage credit
18 payment shall be calculated for each day. The payment per
19 energy storage credit shall be equal to the difference
20 resulting from subtracting from the energy storage strike
21 price the sum of the daily energy volatility index and the
22 reference capacity price for that day. If this difference
23 results in a positive number, the electric utility shall
24 owe the seller this amount multiplied by the number of
25 indexed energy storage credits produced on the relevant
26 day. If this difference results in a negative number, the

HB5856- 219 -LRB103 40655 LNS 73376 b
1 settlement shall be zero. The parties shall cash settle
2 every month, summing up all settlements for the prior
3 month.
4 (2) For tolling agreements, the purchase price shall
5 be the tolling rate as bid by the winning bidder.
6 (3) For pricing structures that are neither indexed
7 credits nor tolling agreements, the Agency, after
8 consideration of feedback from potential bidders and in
9 consideration of financiability, shall develop
10 methodologies for pricing structure and bidding
11 procedures.
12 For the purposes of this subsection:
13 "Developer experience" means the experience of a bidder or
14its affiliates assessed by the Agency, including based on
15quantity of energy projects brought to commercial operation,
16quantity of energy projects under ownership, and awards of
17incentive contracts.
18 "Project viability" means an assessment by the Agency, for
19the purposes of bid evaluation, of the project's potential to
20reach commercial operation as assessed by standards developed
21by the Agency regarding permitting milestones, interconnection
22milestones, and site control milestones.
23 (d) All procurements under this Section shall comply with
24the geographic requirements in subparagraph (I) of paragraph
25(1) of subsection (c) of Section 1-75 and shall follow the
26procurement processes and procedures described in this Section

HB5856- 220 -LRB103 40655 LNS 73376 b
1and Section 16-111.5 of the Public Utilities Act, to the
2extent practicable, and these processes and procedures may be
3expedited to accommodate the schedule established by this
4Section. The Agency shall require all bidders to pay to the
5Agency a nonrefundable deposit of $10,000 per bid. Bidders
6shall also demonstrate experience developing commercial
7readiness. The winning bidders shall comply with the
8prevailing wage requirements in subparagraph (Q) of paragraph
9(1) of subsection (c) of Section 1-75 and the equity
10accountability system requirements in subsection (c-10) of
11Section 1-75. As used in this subsection (d), "developing to
12commercial readiness" means having notice to proceed, owning,
13or operating energy facilities with a combined nameplate
14capacity of at least 100 megawatts.
15 (e) No later than December 31, 2026, and every 2 years
16thereafter, the Agency shall conduct an analysis to determine
17whether the contracted quantity of energy storage in energy
18storage capacity and energy storage duration is sufficient to
19support the State's renewable energy standards and carbon
20emission standards. To conduct the analysis, the Agency shall
21retain an independent consultant with experience in wholesale
22electric system modeling in PJM and MISO and may seek the
23support of the United States Department of Energy and National
24Labs to conduct its analysis. The independent consultant shall
25use a production cost model, capacity expansion model, or
26similar comprehensive analysis of the electricity systems and

HB5856- 221 -LRB103 40655 LNS 73376 b
1shall provide opportunities for stakeholders to provide
2feedback on the scope, inputs, and assumptions used in the
3analysis. The Agency is authorized to collect costs for
4conducting the analysis from electric utilities. The electric
5utilities are authorized to recover the cost of the analysis
6as part of the recovery of the cost of energy storage credits,
7as authorized in this Section and Section 16-108 of the Public
8Utilities Act. If the Agency determines that the need for
9energy storage capacity or energy storage duration is greater
10than the energy storage credit target in this Section, the
11Agency shall establish, and the Commission shall approve, new
12energy storage credit targets to meet the identified need. If
13the Agency determines that deployment of energy storage beyond
142030 will not be achieved through wholesale market prices and
15other energy storage programs established by the State, the
16Agency shall establish additional targets for years beyond
172030.
18 (f) The Agency shall include in the long-term procurement
19plan the energy storage duration of energy storage systems
20from which the Agency shall procure energy storage credits.
21Informed by the analysis described in subsection (e), when
22available, the Agency shall designate the energy storage
23duration or durations and the amount of energy storage
24capacity at each duration from which the Agency intends to
25procure energy storage credits. The long-term procurement plan
26shall further propose allocation of procurements between

HB5856- 222 -LRB103 40655 LNS 73376 b
1indexed credits and tolling agreements, taking into
2consideration factors including timely commercial operation of
3storage resources.
4 (g) The Agency shall identify in the long-term procurement
5plan the regional transmission organization or independent
6system operator to which energy storage systems shall be
7interconnected in order to be eligible to offer a strike price
8for energy storage credits. For all solicitations prior to the
9delivery year 2028, the Agency shall strive to procure at
10least 70% of energy storage credits from energy storage
11systems interconnected to MISO, and at least 10% of energy
12storage credits from energy storage systems located within a
13city with population of more than 1,000,000 people and
14interconnected to PJM Interconnection, LLC. For solicitations
15in the delivery year 2028 and thereafter, and informed by the
16analysis described in subsection (e), the Agency shall
17designate the regional transmission organization or
18independent system operator to which energy storage systems
19shall be interconnected in order to be eligible to offer a
20strike price for energy storage credits. Following
21solicitation and receipt of feedback from stakeholders
22including potential bidders, the Agency shall propose in the
23long-term procurement plan key terms and conditions of the
24standard contracts for indexed credit and tolling agreements.
25The key terms shall be designed to ensure the agreements are
26financeable and to incentivize development.

HB5856- 223 -LRB103 40655 LNS 73376 b
1 (h) The Agency shall procure cost-effective energy storage
2credits in at least the amounts identified in subsection (a).
3The procurement administrator shall establish confidential
4price benchmarks based on publicly available data on regional
5technology costs. Confidential benchmarks shall be developed
6by the procurement administrator, in consultation with
7Commission staff, Agency staff, and the procurement monitor,
8and shall be subject to Commission review and approval.
9Benchmarks shall reflect development, financing, and related
10costs resulting from requirements imposed through other
11provisions of State law. As used in this subsection (h), "cost
12effective" means that the energy storage credit strike price
13does not exceed confidential benchmarks.
14 (i) When developing each storage procurement plan, upon
15solicitation from stakeholders, the Agency shall consider
16additional procurement approaches that would result in the
17electric utilities contracting for energy storage to achieve
18the requirements in subsection (a).
19 (j) Storage energy credits procured under this Section
20must be from energy storage systems built by general
21contractors that enter into a project labor agreement prior to
22construction. The project labor agreement shall be filed with
23the Director in accordance with procedures established by the
24Agency through its storage procurement plan. Any information
25submitted to the Agency under this subsection shall be
26considered commercially sensitive information. At a minimum,

HB5856- 224 -LRB103 40655 LNS 73376 b
1the project labor agreement must provide the names, addresses,
2and occupations of the owner of the plant and the individuals
3representing the labor organization employees participating in
4the project labor agreement in accordance with the Project
5Labor Agreements Act. The agreement must also specify the
6terms and conditions as described in this Act.
7 (k) In order to promote the competitive development of
8energy storage system in furtherance of the State's interest
9in the health, safety, and welfare of its residents, storage
10credits shall not be eligible to be selected under this
11Section if they are sourced from an energy storage system
12whose costs were being recovered through rates regulated by
13this State or any other state or states on or after January 1,
142017. Each contract executed to purchase storage credits under
15this Section shall provide for the contract's termination if
16the costs of the energy storage system supplying the storage
17credits subsequently begin to be recovered through rates
18regulated by this State or any other state or states. Each
19contract shall provide that, in the event the costs of the
20energy storage system supplying the storage credits
21subsequently begin to be recovered through rates regulated by
22this State or any other state or states, the supplier of the
23credits must return 110% of all payments received under the
24contract. Amounts returned under the requirements of this
25subsection shall be refunded to ratepayers. No entity shall be
26permitted to bid unless it certifies to the Agency that it is

HB5856- 225 -LRB103 40655 LNS 73376 b
1not an electric utility, as defined in Section 16-102 of the
2Public Utilities Act, serving more than 10,000 customers in
3the State.
4 (l) The Agency shall require that as a prerequisite to
5payment for any storage credits that the winning bidder
6provide the Agency or its designee a copy of the
7interconnection agreement under which the applicable energy
8storage system is connected to the transmission or
9distribution system.
10 (m) To ensure the successful development of new energy
11storage systems for procurements under this Section, a winning
12bidder or the current seller under contract countersigned by
13an electric utility counterparty may petition the Commission
14to revise the terms in the contract. Prior to such petition,
15upon request by the winning bidder or seller, the Agency shall
16negotiate directly with the winning bidder or seller. If
17following the direct negotiations, the Agency and the winning
18bidder reach an agreement on amended terms or a strike price
19and the Agency finds that the amended terms or strike price
20reflect a change in circumstances since the date of the bid
21based on circumstances unforeseeable at the time of the bid,
22upon petition by the winning bidder or current seller, then
23the Commission shall issue an order directing the utility
24counterparty to execute a form amendment drafted by the Agency
25with the revised terms or the strike price. The Agency shall
26provide the amendment to the utility within 15 business days

HB5856- 226 -LRB103 40655 LNS 73376 b
1after the Commission's order and the utility buyer shall
2execute the amendment not more than 7 calendar days after
3delivery by the Agency. The Agency shall develop the form
4amendment following comment by interested parties.
5 (20 ILCS 3855/1-94 new)
6 Sec. 1-94. Firm energy resource procurement plan. The
7Agency is authorized to develop and implement a firm energy
8resource procurement plan for new resources, including
9initiating proceedings and conducting competitive
10solicitations to deploy new long-duration and multi-day energy
11storage. The procurement plan shall ensure regular procurement
12opportunities to deploy new long-duration and multi-day energy
13storage resources by 2030 and shall ensure stable, competitive
14resource development at a pace needed to ensure grid
15reliability and resilience during atypical or extreme grid
16conditions that may occur at least once in 20 years while
17meeting the emissions requirements of Section 9.15 of the
18Environmental Protection Act. The Agency's plan shall ensure
19that a minimum of 4 new long-duration or multi-day energy
20storage resources, each with a rated capacity greater than 20
21megawatts, shall be deployed or contracted by the end of
22delivery year 2026. Within one year after the effective date
23of this amendatory Act of the 103rd General Assembly, the
24Agency shall develop a firm energy resource procurement plan
25in accordance with this Section and Section 16-111.5 of the

HB5856- 227 -LRB103 40655 LNS 73376 b
1Public Utilities Act.
2 Section 10. The Public Utilities Act is amended by
3changing Sections 16-107.5, 16-107.6, 16-108, and 16-111.5 and
4by adding Sections 8-513, 16-107.9, 16-107.10, and 16-107.11
5and Article XXIII as follows:
6 (220 ILCS 5/8-513 new)
7 Sec. 8-513. Staffing adequacy.
8 (a) The General Assembly finds and declares that devotion
9of adequate resources, including human resources and technical
10resources, to interconnection of electric generation to the
11electric distribution grid and transmission grid are necessary
12to meeting the State's renewable energy goals, including the
13goals set out in Section 1-75 of the Illinois Power Agency Act.
14The General Assembly further finds that insufficient human
15resources or inadequate systems, recordkeeping, or technical
16ability to interconnection by electric utilities risks delays,
17mistakes, and disputes under applicable interconnection
18procedures.
19 (b) Each electric utility, as defined in Section 16-102,
20shall demonstrate sufficient resources devoted to
21interconnection.
22 (c) The Commission shall review in a contested proceeding
23the compliance of each electric utility with the electric
24utility's individual compliance with obligations under

HB5856- 228 -LRB103 40655 LNS 73376 b
1subsection (b). If the Commission, after notice and hearing,
2finds that an electric utility did not meet its obligations
3under subsection (b), or is at risk of not meeting such
4obligations in the future, the Commission may require the
5electric utility to submit a compliance plan to meet such
6obligations. The Commission shall approve or approve with
7modifications a compliance plan if the Commission finds that
8the compliance plan is likely to ensure compliance with the
9electric utility's obligations under subsection (b), or likely
10with modifications to ensure compliance.
11 (d) As used in this Section:
12 "Interconnection" means the steps to interconnect
13 electric generation fueled by renewable resources, energy
14 storage, or a combination of generation fueled by
15 renewable resources and storage under procedures set out
16 in this Act, rules adopted by the Commission, PJM
17 Interconnection, Inc. or its successor, or Midcontinent
18 Independent System Operator or its successor.
19 "Resources" means the combination of employees,
20 independent contractors, vendors, and systems and software
21 that directly support interconnection but shall not
22 include the transformers, reclosers, line, and similar
23 physical assets used to connect or upgrade the
24 distribution or transmission grids.
25 (220 ILCS 5/16-107.5)

HB5856- 229 -LRB103 40655 LNS 73376 b
1 Sec. 16-107.5. Net electricity metering.
2 (a) The General Assembly finds and declares that a program
3to provide net electricity metering, as defined in this
4Section, for eligible customers can encourage private
5investment in renewable energy resources, stimulate economic
6growth, enhance the continued diversification of Illinois'
7energy resource mix, and protect the Illinois environment.
8Further, to achieve the goals of this Act that robust options
9for customer-site distributed generation continue to thrive in
10Illinois, the General Assembly finds that a predictable
11transition must be ensured for customers between full net
12metering at the retail electricity rate to the distribution
13generation rebate described in Section 16-107.6.
14 (b) As used in this Section, (i) "community renewable
15generation project" shall have the meaning set forth in
16Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
17customer" means a retail customer that owns, hosts, or
18operates, including any third-party owned systems, a solar,
19wind, or other eligible renewable electrical generating
20facility that is located on the customer's premises or
21customer's side of the billing meter and is intended primarily
22to offset the customer's own current or future electrical
23requirements; (iii) "electricity provider" means an electric
24utility or alternative retail electric supplier; (iv)
25"eligible renewable electrical generating facility" means a
26generator, which may include the co-location of an energy

HB5856- 230 -LRB103 40655 LNS 73376 b
1storage system, that is interconnected under rules adopted by
2the Commission and is powered by solar electric energy, wind,
3dedicated crops grown for electricity generation, agricultural
4residues, untreated and unadulterated wood waste, livestock
5manure, anaerobic digestion of livestock or food processing
6waste, fuel cells or microturbines powered by renewable fuels,
7or hydroelectric energy; (v) "net electricity metering" (or
8"net metering") means the measurement, during the billing
9period applicable to an eligible customer, of the net amount
10of electricity supplied by an electricity provider to the
11customer or provided to the electricity provider by the
12customer or subscriber; (vi) "subscriber" shall have the
13meaning as set forth in Section 1-10 of the Illinois Power
14Agency Act; (vii) "subscription" shall have the meaning set
15forth in Section 1-10 of the Illinois Power Agency Act; (viii)
16"energy storage system" means commercially available
17technology that is capable of absorbing energy and storing it
18for a period of time for use at a later time, including, but
19not limited to, electrochemical, thermal, and
20electromechanical technologies, and may be interconnected
21behind the customer's meter or interconnected behind its own
22meter; and (ix) "future electrical requirements" means modeled
23electrical requirements upon occupation of a new or vacant
24property, and other reasonable expectations of future
25electrical use, as well as, for occupied properties, a
26reasonable approximation of the annual load of 2 electric

HB5856- 231 -LRB103 40655 LNS 73376 b
1vehicles and, for non-electric heating customers, a reasonable
2approximation of the incremental electric load associated with
3fuel switching. The approximations shall be applied to the
4appropriate net metering tariff and do not need to be unique to
5each individual eligible customer. The utility shall submit
6these approximations to the Commission for review,
7modification, and approval.
8 (c) A net metering facility shall be equipped with
9metering equipment that can measure the flow of electricity in
10both directions at the same rate.
11 (1) 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-hour basis
15 and electric supply service is not provided based on
16 hourly pricing, this shall typically be accomplished
17 through use of a single, bi-directional meter. If the
18 eligible customer's existing electric revenue meter does
19 not meet this requirement, the electricity provider shall
20 arrange for the local electric utility or a meter service
21 provider to install and maintain a new revenue meter at
22 the electricity provider's expense, which may be the smart
23 meter described by subsection (b) of Section 16-108.5 of
24 this Act.
25 (2) For eligible customers whose electric service has
26 not been declared competitive pursuant to Section 16-113

HB5856- 232 -LRB103 40655 LNS 73376 b
1 of this Act as of July 1, 2011 and whose electric delivery
2 service is provided and measured on a kilowatt demand
3 basis and electric supply service is not provided based on
4 hourly pricing, this shall typically be accomplished
5 through use of a dual channel meter capable of measuring
6 the flow of electricity both into and out of the
7 customer's facility at the same rate and ratio. If such
8 customer's existing electric revenue meter does not meet
9 this requirement, then the electricity provider shall
10 arrange for the local electric utility or a meter service
11 provider to install and maintain a new revenue meter at
12 the electricity provider's expense, which may be the smart
13 meter described by subsection (b) of Section 16-108.5 of
14 this Act.
15 (3) For all other eligible customers, until such time
16 as the local electric utility installs a smart meter, as
17 described by subsection (b) of Section 16-108.5 of this
18 Act, the electricity provider may arrange for the local
19 electric utility or a meter service provider to install
20 and maintain metering equipment capable of measuring the
21 flow of electricity both into and out of the customer's
22 facility at the same rate and ratio, typically through the
23 use of a dual channel meter. If the eligible customer's
24 existing electric revenue meter does not meet this
25 requirement, then the costs of installing such equipment
26 shall be paid for by the customer.

HB5856- 233 -LRB103 40655 LNS 73376 b
1 (d) An electricity provider shall measure and charge or
2credit for the net electricity supplied to eligible customers
3or provided by eligible customers whose electric service has
4not been declared competitive pursuant to Section 16-113 of
5this Act as of July 1, 2011 and whose electric delivery service
6is provided and measured on a kilowatt-hour basis and electric
7supply service is not provided based on hourly pricing in the
8following manner:
9 (1) If the amount of electricity used by the customer
10 during the billing period exceeds the amount of
11 electricity produced by the customer, the electricity
12 provider shall charge the customer for the net electricity
13 supplied to and used by the customer as provided in
14 subsection (e-5) of this Section.
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, the electricity provider supplying that customer
19 shall apply a 1:1 kilowatt-hour credit to a subsequent
20 bill for service to the customer for the net electricity
21 supplied to the electricity provider. The electricity
22 provider shall continue to carry over any excess
23 kilowatt-hour credits earned and apply those credits to
24 subsequent billing periods to offset any
25 customer-generator consumption in those billing periods
26 until all credits are used or until the end of the

HB5856- 234 -LRB103 40655 LNS 73376 b
1 annualized period.
2 (3) At the end of the year or annualized over the
3 period that service is supplied by means of net metering,
4 or in the event that the retail customer terminates
5 service with the electricity provider prior to the end of
6 the year or the annualized period, any remaining credits
7 in the customer's account shall expire.
8 (d-5) An electricity provider shall measure and charge or
9credit for the net electricity supplied to eligible customers
10or provided by eligible customers whose electric service has
11not been declared competitive pursuant to Section 16-113 of
12this Act as of July 1, 2011 and whose electric delivery service
13is provided and measured on a kilowatt-hour basis and electric
14supply service is provided based on hourly pricing or
15time-of-use rates in the following manner:
16 (1) If the amount of electricity used by the customer
17 during any hourly period or time-of-use period exceeds the
18 amount of electricity produced by the customer, the
19 electricity provider shall charge the customer for the net
20 electricity supplied to and used by the customer according
21 to the terms of the contract or tariff to which the same
22 customer would be assigned to or be eligible for if the
23 customer was not a net metering customer.
24 (2) If the amount of electricity produced by a
25 customer during any hourly period or time-of-use period
26 exceeds the amount of electricity used by the customer

HB5856- 235 -LRB103 40655 LNS 73376 b
1 during that hourly period or time-of-use period, the
2 energy provider shall apply a credit for the net
3 kilowatt-hours produced in such period. The credit shall
4 consist of an energy credit and a delivery service credit.
5 The energy credit shall be valued at the same price per
6 kilowatt-hour as the electric service provider would
7 charge for kilowatt-hour energy sales during that same
8 hourly period or time-of-use period. The delivery credit
9 shall be equal to the net kilowatt-hours produced in such
10 hourly period or time-of-use period times a credit that
11 reflects all kilowatt-hour based charges in the customer's
12 electric service rate, excluding energy charges.
13 (e) An electricity provider shall measure and charge or
14credit for the net electricity supplied to eligible customers
15whose electric service has not been declared competitive
16pursuant to Section 16-113 of this Act as of July 1, 2011 and
17whose electric delivery service is provided and measured on a
18kilowatt demand basis and electric supply service is not
19provided based on hourly pricing in the following manner:
20 (1) If the amount of electricity used by the customer
21 during the billing period exceeds the amount of
22 electricity produced by the customer, then the electricity
23 provider shall charge the customer for the net electricity
24 supplied to and used by the customer as provided in
25 subsection (e-5) of this Section. The customer shall
26 remain responsible for all taxes, fees, and utility

HB5856- 236 -LRB103 40655 LNS 73376 b
1 delivery charges that would otherwise be applicable to the
2 net amount of electricity used by the customer.
3 (2) If the amount of electricity produced by a
4 customer during the billing period exceeds the amount of
5 electricity used by the customer during that billing
6 period, then the electricity provider supplying that
7 customer shall apply a 1:1 kilowatt-hour credit that
8 reflects the kilowatt-hour based charges in the customer's
9 electric service rate to a subsequent bill for service to
10 the customer for the net electricity supplied to the
11 electricity provider. The electricity provider shall
12 continue to carry over any excess kilowatt-hour credits
13 earned and apply those credits to subsequent billing
14 periods to offset any customer-generator consumption in
15 those billing periods until all credits are used or until
16 the end of the annualized period.
17 (3) At the end of the year or annualized over the
18 period that service is supplied by means of net metering,
19 or in the event that the retail customer terminates
20 service with the electricity provider prior to the end of
21 the year or the annualized period, any remaining credits
22 in the customer's account shall expire.
23 (e-5) An electricity provider shall provide electric
24service to eligible customers who utilize net metering at
25non-discriminatory rates that are identical, with respect to
26rate structure, retail rate components, and any monthly

HB5856- 237 -LRB103 40655 LNS 73376 b
1charges, to the rates that the customer would be charged if not
2a net metering customer. An electricity provider shall not
3charge net metering customers any fee or charge or require
4additional equipment, insurance, or any other requirements not
5specifically authorized by interconnection standards
6authorized by the Commission, unless the fee, charge, or other
7requirement would apply to other similarly situated customers
8who are not net metering customers. The customer will remain
9responsible for all taxes, fees, and utility delivery charges
10that would otherwise be applicable to the net amount of
11electricity used by the customer. Subsections (c) through (e)
12of this Section shall not be construed to prevent an
13arms-length agreement between an electricity provider and an
14eligible customer that sets forth different prices, terms, and
15conditions for the provision of net metering service,
16including, but not limited to, the provision of the
17appropriate metering equipment for non-residential customers.
18 (f) Notwithstanding the requirements of subsections (c)
19through (e-5) of this Section, an electricity provider must
20require dual-channel metering for customers operating eligible
21renewable electrical generating facilities to whom the
22provisions of neither subsection (d), (d-5), nor (e) of this
23Section apply. In such cases, electricity charges and credits
24shall be determined as follows:
25 (1) The electricity provider shall assess and the
26 customer remains responsible for all taxes, fees, and

HB5856- 238 -LRB103 40655 LNS 73376 b
1 utility delivery charges that would otherwise be
2 applicable to the gross amount of kilowatt-hours supplied
3 to the eligible customer by the electricity provider.
4 (2) Each month that service is supplied by means of
5 dual-channel metering, the electricity provider shall
6 compensate the eligible customer for any excess
7 kilowatt-hour credits at the electricity provider's
8 avoided cost of electricity supply over the monthly period
9 or as otherwise specified by the terms of a power-purchase
10 agreement negotiated between the customer and electricity
11 provider.
12 (3) For all eligible net metering customers taking
13 service from an electricity provider under contracts or
14 tariffs employing hourly or time-of-use rates, any monthly
15 consumption of electricity shall be calculated according
16 to the terms of the contract or tariff to which the same
17 customer would be assigned to or be eligible for if the
18 customer was not a net metering customer. When those same
19 customer-generators are net generators during any discrete
20 hourly or time-of-use period, the net kilowatt-hours
21 produced shall be valued at the same price per
22 kilowatt-hour as the electric service provider would
23 charge for retail kilowatt-hour sales during that same
24 time-of-use period.
25 (g) For purposes of federal and State laws providing
26renewable energy credits or greenhouse gas credits, the

HB5856- 239 -LRB103 40655 LNS 73376 b
1eligible customer shall be treated as owning and having title
2to the renewable energy attributes, renewable energy credits,
3and greenhouse gas emission credits related to any electricity
4produced by the qualified generating unit. The electricity
5provider may not condition participation in a net metering
6program on the signing over of a customer's renewable energy
7credits; provided, however, this subsection (g) shall not be
8construed to prevent an arms-length agreement between an
9electricity provider and an eligible customer that sets forth
10the ownership or title of the credits.
11 (h) Within 120 days after the effective date of this
12amendatory Act of the 95th General Assembly, the Commission
13shall establish standards for net metering and, if the
14Commission has not already acted on its own initiative,
15standards for the interconnection of eligible renewable
16generating equipment to the utility system. The
17interconnection standards shall address any procedural
18barriers, delays, and administrative costs associated with the
19interconnection of customer-generation while ensuring the
20safety and reliability of the units and the electric utility
21system. The Commission shall consider the Institute of
22Electrical and Electronics Engineers (IEEE) Standard 1547 and
23the issues of (i) reasonable and fair fees and costs, (ii)
24clear timelines for major milestones in the interconnection
25process, (iii) nondiscriminatory terms of agreement, and (iv)
26any best practices for interconnection of distributed

HB5856- 240 -LRB103 40655 LNS 73376 b
1generation.
2 (h-5) Within 90 days after the effective date of this
3amendatory Act of the 103rd General Assembly amendatory Act of
4the 102nd General Assembly, the Commission shall:
5 (1) establish an Interconnection Working Group. The
6 working group shall include representatives from electric
7 utilities, developers of renewable electric generating
8 facilities, other industries that regularly apply for
9 interconnection with the electric utilities,
10 representatives of distributed generation customers, the
11 Commission Staff, and such other stakeholders with a
12 substantial interest in the topics addressed by the
13 Interconnection Working Group. The Interconnection Working
14 Group shall address at least the following issues:
15 (A) cost and best available technology for
16 interconnection and metering, including the
17 standardization and publication of standard costs;
18 (B) transparency, accuracy and use of the
19 distribution interconnection queue and hosting
20 capacity maps;
21 (C) distribution system upgrade cost avoidance
22 through use of advanced inverter functions;
23 (D) predictability of the queue management process
24 and enforcement of timelines;
25 (E) benefits and challenges associated with group
26 studies and cost sharing;

HB5856- 241 -LRB103 40655 LNS 73376 b
1 (F) minimum requirements for application to the
2 interconnection process and throughout the
3 interconnection process to avoid queue clogging
4 behavior;
5 (G) process and customer service for
6 interconnecting customers adopting distributed energy
7 resources, including energy storage;
8 (H) options for metering distributed energy
9 resources, including energy storage;
10 (I) interconnection of new technologies, including
11 smart inverters and energy storage;
12 (J) collect, share, and examine data on Level 1
13 interconnection costs, including cost and type of
14 upgrades required for interconnection, and use this
15 data to inform the final standardized cost of Level 1
16 interconnection; and
17 (K) such other technical, policy, and tariff
18 issues related to and affecting interconnection
19 performance and customer service as determined by the
20 Interconnection Working Group.
21 The Commission may create subcommittees of the
22 Interconnection Working Group to focus on specific issues
23 of importance, as appropriate. The Ombudsman, on behalf of
24 the Interconnection Working Group, shall report to the
25 Commission on recommended improvements to interconnection
26 rules and tariffs and policies as determined by the

HB5856- 242 -LRB103 40655 LNS 73376 b
1 Interconnection Working Group at least every 6 months.
2 Such reports shall include consensus recommendations of
3 the Interconnection Working Group and, if applicable,
4 additional recommendations for which consensus was not
5 reached. The Commission shall use the report from the
6 Interconnection Working Group to determine whether
7 processes should be commenced to formally codify or
8 implement the recommendations;
9 (2) designate the Ombudsperson described in Section
10 23-110, or his or her designee within the Office of
11 Interconnection and Renewable Development, to act as the
12 facilitator for the Interconnection Working Group for the
13 purpose of resolving create or contract for an Ombudsman
14 to resolve interconnection disputes through mediation or
15 non-binding arbitration, to the extent mediation or
16 non-binding arbitration is available under rules adopted
17 by the Commission. As the facilitator for the
18 Interconnection Working Group, the Ombudsperson shall
19 convene stakeholders to set agendas for discussions, lead
20 meetings, ensure notes are distributed to members, and
21 perform other tasks necessary to support the good-faith
22 advancement of discussions. The Ombudsperson Ombudsman may
23 be paid in full or in part through fees levied on the
24 initiators of the dispute; and
25 (3) determine a single standardized cost for Level 1
26 interconnections, which shall not exceed $200; .

HB5856- 243 -LRB103 40655 LNS 73376 b
1 (4) require all electric utilities to perform a system
2 impact and facilities study to provide a detailed
3 breakdown of the non-binding costs of operation and an
4 estimate that individually itemizes operational costs,
5 including equipment by type or model, labor, operation and
6 maintenance, engineering and design, permitting, easements
7 and rights-of-way, direct overhead, and indirect overhead;
8 (5) prohibit electric utilities from recovering from
9 an interconnection customer more than 125% of the
10 non-binding cost estimate in the system impact and
11 facilities study described in paragraph (4). An electric
12 utility with a Multi-Year Rate Plan may recover prudent
13 and reasonable costs of interconnection that are not
14 recoverable from the interconnection customer under this
15 paragraph from all customers through its Multi-Year Rate
16 Plan;
17 (6) open a proceeding, not to exceed 240 days in
18 duration, to create a uniform standard for cost-sharing of
19 interconnections. As used in this paragraph, "cost-sharing
20 of interconnections" means a system under which an
21 electric utility assigns the costs of upgrades to a
22 distribution-voltage substation that exceeds $5,000,000
23 between the interconnection customer that initially causes
24 the upgrade and interconnection customers subsequent in
25 the interconnection queue, not to exceed 10 customers,
26 that directly benefit from the increased hosting capacity

HB5856- 244 -LRB103 40655 LNS 73376 b
1 from the upgrade, including applicants that subsequently
2 enter the queue;
3 (7) adopt rules, in addition to dispute resolution
4 provisions under the Commission's rules authorized by
5 subsection (h), as long as, upon complaint by an electric
6 utility, an interconnection customer, or an
7 interconnection applicant, the Ombudsperson, or his or her
8 designee, provides a recommended resolution of any dispute
9 within 5 business days after receiving the complaint. The
10 electric utility, the interconnection customer, the
11 interconnection applicant, or any other party authorized
12 to initiate dispute resolution under the Commission's
13 rules authorized by subsection (h) may include the
14 Ombudsperson's recommendation in any dispute resolution.
15 Nothing in this paragraph prohibits the Ombudsperson from
16 taking part in a dispute as required by this Section or the
17 Commission's rules;
18 (8) require each electric utility to offer flexible
19 interconnection. An interconnection applicant may propose
20 flexible interconnection options and an electric utility
21 shall not unreasonably deny the proposal. If curtailment
22 is expected under the flexible interconnection option, the
23 electric utility shall provide an analysis of the expected
24 rate of curtailment, inclusive of calculations, as well as
25 load, generation, contingency, and system limit
26 assumptions used. Each study of interconnection costs with

HB5856- 245 -LRB103 40655 LNS 73376 b
1 a cost exceeding $0.30 per watt shall include an
2 evaluation of flexible interconnection options. As used in
3 this paragraph, "flexible interconnection" means active or
4 passive hardware, software, or other controls allowing
5 curtailment of distributed energy resources during grid
6 conditions that might otherwise impact safety or
7 reliability of the distribution system;
8 (9) prohibit any electric utility from requiring a
9 deposit for construction of interconnection facilities or
10 distribution upgrades of greater than $1,000,000 and
11 making a payment of more than 25% of the amount before 20
12 business days before the engineering, procurement, and
13 construction of the interconnection facilities or
14 distribution upgrades;
15 (10) require all electric utilities, in studying
16 potential interconnection of distributed energy resources,
17 to present a proposed scope of upgrades and non-binding
18 cost estimate for the native feeder as well as the
19 non-binding cost estimate and scope of upgrades for any
20 other feeders proposed by the utility if different. The
21 interconnection customer shall be entitled to choose
22 between the 2 or more options presented by the electric
23 utility. In addition, the electric utility shall present a
24 separate proposed scope and non-binding cost estimate for
25 exceeding any distributed energy resource capacity limits
26 imposed by the electric utility;

HB5856- 246 -LRB103 40655 LNS 73376 b
1 (11) prohibit the electric utility from conditioning
2 study of an interconnection application on study, deposit,
3 or approval of any other distributed energy resource ahead
4 in queue, however nothing prohibits an electric utility
5 from identifying contingent upgrades for applicants lower
6 in queue. In such case, the electric utility shall
7 identify the projects ahead of the applicant in the queue
8 to the applicant or interconnection customer;
9 (12) require facilities study, as defined under the
10 Commission's rules adopted pursuant to subsection (h), to
11 include analysis of required easements, including the pin
12 number of each parcel on which customer-acquired easements
13 are needed. The electric utility shall allow use of the
14 electric utility's easements for interconnection
15 facilities and distribution upgrades, including
16 interconnection facilities and distribution upgrades
17 constructed by the applicant, interconnection customer, or
18 a third party on their behalf;
19 (13) require each electric utility to provide guidance
20 to applicants lower in queue on how contingent upgrade
21 costs will flow through the interconnection queue,
22 inclusive of the order of projects on which those upgrades
23 will fall, the allowable timelines for the electric
24 distribution utilities to notify the next project
25 following the withdrawal of the responsible project, and
26 establishing timelines for projects on which these

HB5856- 247 -LRB103 40655 LNS 73376 b
1 contingent upgrades fall to either pay the additional
2 deposit amount or withdraw their project;
3 (14) require each utility to maintain a public queue
4 with project-specific information including nameplate
5 capacity, energy storage nameplate capacity, if any,
6 contingent upgrades, if any, and estimated non-binding
7 interconnection cost provided by the electric utility to
8 the applicant or interconnection customer. The Commission
9 may require additional information be provided under this
10 paragraph; and
11 (15) require each electric utility serving more than
12 100,000 customers on January 1, 2023, to the extent not
13 provided in its multi-year grid plan, to submit to the
14 Commission a plan to implement public dynamic hosting
15 capacity maps not later than January 1, 2026. For the
16 purposes of this paragraph, "dynamic hosting capacity
17 maps" means publicly-facing hosting capacity maps that are
18 updated in real time or not less frequently than daily,
19 based on information received or provided by the electric
20 utility.
21 (i) All electricity providers shall begin to offer net
22metering no later than April 1, 2008.
23 (j) An electricity provider shall provide net metering to
24eligible customers according to subsections (d), (d-5), and
25(e). Eligible renewable electrical generating facilities for
26which eligible customers registered for net metering before

HB5856- 248 -LRB103 40655 LNS 73376 b
1January 1, 2025 shall continue to receive net metering
2services according to subsections (d), (d-5), and (e) of this
3Section for the lifetime of the system, regardless of whether
4those retail customers change electricity providers or whether
5the retail customer benefiting from the system changes. On and
6after January 1, 2025, any eligible customer that applies for
7net metering and previously would have qualified under
8subsections (d), (d-5), or (e) shall only be eligible for net
9metering as described in subsection (n).
10 (k) Each electricity provider shall maintain records and
11report annually to the Commission the total number of net
12metering customers served by the provider, as well as the
13type, capacity, and energy sources of the generating systems
14used by the net metering customers. Nothing in this Section
15shall limit the ability of an electricity provider to request
16the redaction of information deemed by the Commission to be
17confidential business information.
18 (l)(1) Notwithstanding the definition of "eligible
19customer" in item (ii) of subsection (b) of this Section, each
20electricity provider shall allow net metering as set forth in
21this subsection (l) and for the following projects, provided
22that only electric utilities serving more than 200,000
23customers as of January 1, 2021 shall provide net metering for
24projects that are eligible for subparagraph (C) of this
25paragraph (1) and have energized after the effective date of
26this amendatory Act of the 102nd General Assembly:

HB5856- 249 -LRB103 40655 LNS 73376 b
1 (A) properties owned or leased by multiple customers
2 that contribute to the operation of an eligible renewable
3 electrical generating facility through an ownership or
4 leasehold interest of at least 200 watts in such facility,
5 such as a community-owned wind project, a community-owned
6 biomass project, a community-owned solar project, or a
7 community methane digester processing livestock waste from
8 multiple sources, provided that the facility is also
9 located within the utility's service territory;
10 (B) individual units, apartments, or properties
11 located in a single building that are owned or leased by
12 multiple customers and collectively served by a common
13 eligible renewable electrical generating facility, such as
14 an office or apartment building, a shopping center or
15 strip mall served by photovoltaic panels on the roof; and
16 (C) subscriptions to community renewable generation
17 projects, including community renewable generation
18 projects on the customer's side of the billing meter of a
19 host facility and partially used for the customer's own
20 load.
21 In addition, the nameplate capacity of the eligible
22renewable electric generating facility that serves the demand
23of the properties, units, or apartments identified in
24paragraphs (1) and (2) of this subsection (l) shall not exceed
255,000 kilowatts in nameplate capacity in total. Any eligible
26renewable electrical generating facility or community

HB5856- 250 -LRB103 40655 LNS 73376 b
1renewable generation project that is powered by photovoltaic
2electric energy and installed after the effective date of this
3amendatory Act of the 99th General Assembly must be installed
4by a qualified person in compliance with the requirements of
5Section 16-128A of the Public Utilities Act and any rules or
6regulations adopted thereunder.
7 (2) Notwithstanding anything to the contrary, an
8electricity provider shall provide credits for the electricity
9produced by the projects described in paragraph (1) of this
10subsection (l). The electricity provider shall provide credits
11that include at least energy supply, capacity, transmission,
12and, if applicable, the purchased energy adjustment on the
13subscriber's monthly bill equal to the subscriber's share of
14the production of electricity from the project, as determined
15by paragraph (3) of this subsection (l). For customers with
16transmission or capacity charges not charged on a
17kilowatt-hour basis, the electricity provider shall prepare a
18reasonable approximation of the kilowatt-hour equivalent value
19and provide that value as a monetary credit. The electricity
20provider shall submit these approximation methodologies to the
21Commission for review, modification, and approval.
22Notwithstanding anything to the contrary, customers on payment
23plans or participating in budget billing programs shall have
24credits applied on a monthly basis.
25 (3) Notwithstanding anything to the contrary and
26regardless of whether a subscriber to an eligible community

HB5856- 251 -LRB103 40655 LNS 73376 b
1renewable generation project receives power and energy service
2from the electric utility or an alternative retail electric
3supplier, for projects eligible under paragraph (C) of
4subparagraph (1) of this subsection (l), electric utilities
5serving more than 200,000 customers as of January 1, 2021
6shall provide the monetary credits to a subscriber's
7subsequent bill for the electricity produced by community
8renewable generation projects. The electric utility shall
9provide monetary credits to a subscriber's subsequent bill at
10the utility's total price to compare equal to the subscriber's
11share of the production of electricity from the project, as
12determined by paragraph (5) of this subsection (l). For the
13purposes of this subsection, "total price to compare" means
14the rate or rates published by the Illinois Commerce
15Commission for energy supply for eligible customers receiving
16supply service from the electric utility, and shall include
17energy, capacity, transmission, and the purchased energy
18adjustment. Notwithstanding anything to the contrary,
19customers on payment plans or participating in budget billing
20programs shall have credits applied on a monthly basis. Any
21applicable credit or reduction in load obligation from the
22production of the community renewable generating projects
23receiving a credit under this subsection shall be credited to
24the electric utility to offset the cost of providing the
25credit. To the extent that the credit or load obligation
26reduction does not completely offset the cost of providing the

HB5856- 252 -LRB103 40655 LNS 73376 b
1credit to subscribers of community renewable generation
2projects as described in this subsection, the electric utility
3may recover the remaining costs through its Multi-Year Rate
4Plan. All electric utilities serving 200,000 or fewer
5customers as of January 1, 2021 shall only provide the
6monetary credits to a subscriber's subsequent bill for the
7electricity produced by community renewable generation
8projects if the subscriber receives power and energy service
9from the electric utility. Alternative retail electric
10suppliers providing power and energy service to a subscriber
11located within the service territory of an electric utility
12not subject to Sections 16-108.18 and 16-118 shall provide the
13monetary credits to the subscriber's subsequent bill for the
14electricity produced by community renewable generation
15projects.
16 (4) If requested by the owner or operator of a community
17renewable generating project, an electric utility serving more
18than 200,000 customers as of January 1, 2021 shall enter into a
19net crediting agreement with the owner or operator to include
20a subscriber's subscription fee on the subscriber's monthly
21electric bill and provide the subscriber with a net credit
22equivalent to the total bill credit value for that generation
23period minus the subscription fee, provided the subscription
24fee is structured as a fixed percentage of bill credit value.
25The net crediting agreement shall set forth payment terms from
26the electric utility to the owner or operator of the community

HB5856- 253 -LRB103 40655 LNS 73376 b
1renewable generating project, and the electric utility may
2charge a net crediting fee to the owner or operator of a
3community renewable generating project that may not exceed 1%
42% of the subscription fee bill credit value. Notwithstanding
5anything to the contrary, an electric utility serving 200,000
6customers or fewer as of January 1, 2021 shall not be obligated
7to enter into a net crediting agreement with the owner or
8operator of a community renewable generating project. For the
9purposes of this paragraph (4), "net crediting" means a
10program offered by an electric utility under which the
11electric utility, upon authorization by or on behalf of a
12subscriber, remits the cash value of the subscription fee to
13the owner or operator of the community renewable generation
14facility, without regard to whether or not the subscriber has
15paid the subscriber's monthly electric bill, and places the
16cash value of the remaining bill credit on the subscriber's
17bill. The utility shall use the same net crediting format for
18subscribers on payment plans or participating in budget
19billing programs.
20 (5) For the purposes of facilitating net metering, the
21owner or operator of the eligible renewable electrical
22generating facility or community renewable generation project
23shall be responsible for determining the amount of the credit
24that each customer or subscriber participating in a project
25under this subsection (l) is to receive in the following
26manner:

HB5856- 254 -LRB103 40655 LNS 73376 b
1 (A) The owner or operator shall, on a monthly basis,
2 provide to the electric utility the kilowatthours of
3 generation attributable to each of the utility's retail
4 customers and subscribers participating in projects under
5 this subsection (l) in accordance with the customer's or
6 subscriber's share of the eligible renewable electric
7 generating facility's or community renewable generation
8 project's output of power and energy for such month. The
9 owner or operator shall electronically transmit such
10 calculations and associated documentation to the electric
11 utility, in a format or method set forth in the applicable
12 tariff, on a monthly basis so that the electric utility
13 can reflect the monetary credits on customers' and
14 subscribers' electric utility bills. The electric utility
15 shall be permitted to revise its tariffs to implement the
16 provisions of this amendatory Act of the 102nd General
17 Assembly. The owner or operator shall separately provide
18 the electric utility with the documentation detailing the
19 calculations supporting the credit in the manner set forth
20 in the applicable tariff.
21 (B) For those participating customers and subscribers
22 who receive their energy supply from an alternative retail
23 electric supplier, the electric utility shall remit to the
24 applicable alternative retail electric supplier the
25 information provided under subparagraph (A) of this
26 paragraph (3) for such customers and subscribers in a

HB5856- 255 -LRB103 40655 LNS 73376 b
1 manner set forth in such alternative retail electric
2 supplier's net metering program, or as otherwise agreed
3 between the utility and the alternative retail electric
4 supplier. The alternative retail electric supplier shall
5 then submit to the utility the amount of the charges for
6 power and energy to be applied to such customers and
7 subscribers, including the amount of the credit associated
8 with net metering.
9 (C) A participating customer or subscriber may provide
10 authorization as required by applicable law that directs
11 the electric utility to submit information to the owner or
12 operator of the eligible renewable electrical generating
13 facility or community renewable generation project to
14 which the customer or subscriber has an ownership or
15 leasehold interest or a subscription. Such information
16 shall be limited to the components of the net metering
17 credit calculated under this subsection (l), including the
18 bill credit rate, total kilowatthours, and total monetary
19 credit value applied to the customer's or subscriber's
20 bill for the monthly billing period.
21 (l-5) Within 90 days after the effective date of this
22amendatory Act of the 102nd General Assembly, each electric
23utility subject to this Section shall file a tariff or tariffs
24to implement the provisions of subsection (l) of this Section,
25which shall, consistent with the provisions of subsection (l),
26describe the terms and conditions under which owners or

HB5856- 256 -LRB103 40655 LNS 73376 b
1operators of qualifying properties, units, or apartments may
2participate in net metering. The Commission shall approve, or
3approve with modification, the tariff within 120 days after
4the effective date of this amendatory Act of the 102nd General
5Assembly.
6 (m) Nothing in this Section shall affect the right of an
7electricity provider to continue to provide, or the right of a
8retail customer to continue to receive service pursuant to a
9contract for electric service between the electricity provider
10and the retail customer in accordance with the prices, terms,
11and conditions provided for in that contract. Either the
12electricity provider or the customer may require compliance
13with the prices, terms, and conditions of the contract.
14 (n) On and after January 1, 2025, the net metering
15services described in subsections (d), (d-5), and (e) of this
16Section shall no longer be offered, except as to those
17eligible renewable electrical generating facilities for which
18retail customers are receiving net metering service under
19these subsections at the time the net metering services under
20those subsections are no longer offered; those systems shall
21continue to receive net metering services described in
22subsections (d), (d-5), and (e) of this Section for the
23lifetime of the system, regardless of if those retail
24customers change electricity providers or whether the retail
25customer benefiting from the system changes. The electric
26utility serving more than 200,000 customers as of January 1,

HB5856- 257 -LRB103 40655 LNS 73376 b
12021 is responsible for ensuring the billing credits continue
2without lapse for the lifetime of systems, as required in
3subsection (o). Those retail customers that begin taking net
4metering service after the date that net metering services are
5no longer offered under such subsections shall be subject to
6the provisions set forth in the following paragraphs (1)
7through (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

HB5856- 258 -LRB103 40655 LNS 73376 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:

HB5856- 259 -LRB103 40655 LNS 73376 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

HB5856- 260 -LRB103 40655 LNS 73376 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)

HB5856- 261 -LRB103 40655 LNS 73376 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
12amendatory Act of the 102nd General Assembly, each electric
13utility subject to this Section shall file a tariff, which
14shall, consistent with the provisions of this Section, propose
15the terms and conditions under which a customer may
16participate in net metering. The tariff for electric utilities
17serving more than 200,000 customers as of January 1, 2021
18shall also provide a streamlined and transparent bill
19crediting system for net metering to be managed by the
20electric utilities. The terms and conditions shall include,
21but are not limited to, that an electric utility shall manage
22and maintain billing of net metering credits and charges
23regardless of if the eligible customer takes net metering
24under an electric utility or alternative retail electric
25supplier. The electric utility serving more than 200,000
26customers as of January 1, 2021 shall process and approve all

HB5856- 262 -LRB103 40655 LNS 73376 b
1net metering applications, even if an eligible customer is
2served by an alternative retail electric supplier; and the
3utility shall forward application approval to the appropriate
4alternative retail electric supplier. Eligibility for net
5metering shall remain with the owner of the utility billing
6address such that, if an eligible renewable electrical
7generating facility changes ownership, the net metering
8eligibility transfers to the new owner. The electric utility
9serving more than 200,000 customers as of January 1, 2021
10shall manage net metering billing for eligible customers to
11ensure full crediting occurs on electricity bills, including,
12but not limited to, ensuring net metering crediting begins
13upon commercial operation date, net metering billing transfers
14immediately if an eligible customer switches from an electric
15utility to alternative retail electric supplier or vice versa,
16and net metering billing transfers between ownership of a
17valid billing address. All transfers referenced in the
18preceding sentence shall include transfer of all banked
19credits. All electric utilities serving 200,000 or fewer
20customers as of January 1, 2021 shall manage net metering
21billing for eligible customers receiving power and energy
22service from the electric utility to ensure full crediting
23occurs on electricity bills, ensuring net metering crediting
24begins upon commercial operation date, net metering billing
25transfers immediately if an eligible customer switches from an
26electric utility to alternative retail electric supplier or

HB5856- 263 -LRB103 40655 LNS 73376 b
1vice versa, and net metering billing transfers between
2ownership of a valid billing address. Alternative retail
3electric suppliers providing power and energy service to
4eligible customers located within the service territory of an
5electric utility serving 200,000 or fewer customers as of
6January 1, 2021 shall manage net metering billing for eligible
7customers to ensure full crediting occurs on electricity
8bills, including, but not limited to, ensuring net metering
9crediting begins upon commercial operation date, net metering
10billing transfers immediately if an eligible customer switches
11from an electric utility to alternative retail electric
12supplier or vice versa, and net metering billing transfers
13between 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 rebate.
17 (a) In this Section:
18 "Additive services" means the services that distributed
19energy resources provide to the energy system and society that
20are not (1) already included in the base rebates for
21system-wide grid services; or (2) otherwise already
22compensated. Additive services may reflect, but shall not be
23limited to, any geographic, time-based, performance-based, and
24other benefits of distributed energy resources, as well as the
25present and future technological capabilities of distributed

HB5856- 264 -LRB103 40655 LNS 73376 b
1energy resources and present and future grid needs.
2 "Distributed energy resource" means a wide range of
3technologies that are located on the customer side of the
4customer's electric meter, including, but not limited to,
5distributed generation, energy storage, electric vehicles, and
6demand response technologies.
7 "Energy storage system" means commercially available
8technology that is capable of absorbing energy and storing it
9for a period of time for use at a later time, including, but
10not limited to, electrochemical, thermal, and
11electromechanical technologies, and may be interconnected
12behind the customer's meter or interconnected behind its own
13meter.
14 "Smart inverter" means a device that converts direct
15current into alternating current and meets the IEEE 1547-2018
16equipment standards. Until devices that meet the IEEE
171547-2018 standard are available, devices that meet the UL
181741 SA standard are acceptable.
19 "Subscriber" has the meaning set forth in Section 1-10 of
20the Illinois Power Agency Act.
21 "Subscription" has the meaning set forth in Section 1-10
22of the Illinois Power Agency Act.
23 "System-wide grid services" means the benefits that a
24distributed energy resource provides to the distribution grid
25for a period of no less than 25 years. System-wide grid
26services do not vary by location, time, or the performance

HB5856- 265 -LRB103 40655 LNS 73376 b
1characteristics of the distributed energy resource.
2System-wide grid services include, but are not limited to,
3avoided or deferred distribution capacity costs, resilience
4and reliability benefits, avoided or deferred distribution
5operation and maintenance costs, distribution voltage and
6power quality benefits, and line loss reductions.
7 "Threshold date" means December 31, 2024 or the date on
8which the utility's tariff or tariffs setting the new
9compensation values established under subsection (e) take
10effect, whichever is later.
11 (b) An electric utility that serves more than 200,000
12customers in the State shall file a petition with the
13Commission requesting approval of the utility's tariff to
14provide a rebate to the owner or operator of distributed
15generation, including third-party owned systems, that meets
16the following criteria:
17 (1) has a nameplate generating capacity no greater
18 than 5,000 kilowatts and is primarily used to offset a
19 customer's electricity load;
20 (2) is located on the customer's side of the billing
21 meter and for the customer's own use;
22 (3) is interconnected to electric distribution
23 facilities owned by the electric utility under rules
24 adopted by the Commission by means of the inverter or
25 smart inverter required by this Section, as applicable.
26 For purposes of this Section, "distributed generation"

HB5856- 266 -LRB103 40655 LNS 73376 b
1shall satisfy the definition of distributed renewable energy
2generation device set forth in Section 1-10 of the Illinois
3Power Agency Act to the extent such definition is consistent
4with the requirements of this Section.
5 In addition, any new photovoltaic distributed generation
6that is installed after June 1, 2017 (the effective date of
7Public Act 99-906) must be installed by a qualified person, as
8defined by subsection (i) of Section 1-56 of the Illinois
9Power Agency Act.
10 The tariff shall include a base rebate that compensates
11distributed generation for the system-wide grid services
12associated with distributed generation and, after the
13proceeding described in subsection (e) of this Section, an
14additional payment or payments for the additive services. The
15tariff shall provide that the smart inverter associated with
16the distributed generation shall provide autonomous response
17to grid conditions through its default settings as approved by
18the Commission. Default settings may not be changed after the
19execution of the interconnection agreement except by mutual
20agreement between the utility and the owner or operator of the
21distributed generation. Nothing in this Section shall negate
22or supersede Institute of Electrical and Electronics Engineers
23equipment standards or other similar standards or
24requirements. The tariff shall not limit the ability of the
25smart inverter or other distributed energy resource to provide
26wholesale market products such as regulation, demand response,

HB5856- 267 -LRB103 40655 LNS 73376 b
1or other services, or limit the ability of the owner of the
2smart inverter or the other distributed energy resource to
3receive compensation for providing those wholesale market
4products or services.
5 (b-5) Within 30 days after the effective date of this
6amendatory Act of the 102nd General Assembly, each electric
7public utility with 3,000,000 or more retail customers shall
8file a tariff with the Commission that further compensates any
9retail customer that installs or has installed photovoltaic
10facilities paired with energy storage facilities on or
11adjacent to its premises for the benefits the facilities
12provide to the distribution grid. The tariff shall provide
13that, in addition to the other rebates identified in this
14Section, the electric utility shall rebate to such retail
15customer (i) the previously incurred and future costs of
16installing interconnection facilities and related
17infrastructure to enable full participation in the PJM
18Interconnection, LLC or its successor organization frequency
19regulation market; and (ii) all wholesale demand charges
20incurred after the effective date of this amendatory Act of
21the 102nd General Assembly. The Commission shall approve, or
22approve with modification, the tariff within 120 days after
23the utility's filing.
24 (c) The proposed tariff authorized by subsection (b) of
25this Section shall include the following participation terms
26for rebates to be applied under this Section for distributed

HB5856- 268 -LRB103 40655 LNS 73376 b
1generation that satisfies the criteria set forth in subsection
2(b) of this Section:
3 (1) The owner or operator of distributed generation
4 that services customers not eligible for net metering
5 under subsection (d), (d-5), or (e) of Section 16-107.5 of
6 this Act may apply for a rebate as provided for in this
7 Section. Until the threshold date, the value of the rebate
8 shall be $250 per kilowatt of nameplate generating
9 capacity, measured as nominal DC power output, of that
10 customer's distributed generation. To the extent the
11 distributed generation also has an associated energy
12 storage, then the energy storage system shall be
13 separately compensated with a base rebate of $250 per
14 kilowatt-hour of nameplate capacity. Any distributed
15 generation device that is compensated for storage in this
16 subsection (1) before the threshold date shall participate
17 in one or more programs determined through the Multi-Year
18 Integrated Grid Planning process that are designed to meet
19 peak reduction and flexibility, the virtual power plant
20 program described in Section 16-107.9, or the peak
21 remediation program described in Section 16-107.10. After
22 the threshold date, the value of the base rebate and
23 additional compensation for any additive services shall be
24 as determined by the Commission in the proceeding
25 described in subsection (e) of this Section, provided that
26 the value of the base rebate for system-wide grid services

HB5856- 269 -LRB103 40655 LNS 73376 b
1 shall not be lower than $250 per kilowatt of nameplate
2 generating capacity of distributed generation or community
3 renewable generation project.
4 (2) The owner or operator of distributed generation
5 that, before the threshold date, would have been eligible
6 for net metering under subsection (d), (d-5), or (e) of
7 Section 16-107.5 of this Act and that has not previously
8 received a distributed generation rebate, may apply for a
9 rebate as provided for in this Section. Until the
10 threshold date, the value of the base rebate shall be $300
11 per kilowatt of nameplate generating capacity, measured as
12 nominal DC power output, of the distributed generation.
13 The owner or operator of distributed generation that,
14 before the threshold date, is eligible for net metering
15 under subsection (d), (d-5), or (e) of Section 16-107.5 of
16 this Act may apply for a base rebate for an energy storage
17 device that uses the same smart inverter as the
18 distributed generation, regardless of whether the
19 distributed generation applies for a rebate for the
20 distributed generation device. The energy storage system
21 shall be separately compensated at a base payment of $300
22 per kilowatt-hour of nameplate capacity. Any distributed
23 generation device that is compensated for storage in this
24 subsection (2) before the threshold date shall participate
25 in the virtual power plant program described in Section
26 16-107.9, or at least one demand response a peak time

HB5856- 270 -LRB103 40655 LNS 73376 b
1 rebate program, hourly pricing program, or time-of-use
2 rate program that is offered by the applicable electric
3 utility, an alternative retail electric supplier, or an
4 entity qualified to offer demand response that is not an
5 alternative retail electric supplier. After the threshold
6 date, the value of the base rebate and additional
7 compensation for any additive services shall be as
8 determined by the Commission in the proceeding described
9 in subsection (e) of this Section, provided that, prior to
10 December 31, 2029, the value of the base rebate for
11 system-wide services shall not be lower than $300 per
12 kilowatt of nameplate generating capacity of distributed
13 generation, after which it shall not be lower than $250
14 per kilowatt of nameplate capacity.
15 (3) Upon approval of a rebate application submitted
16 under this subsection (c), the retail customer shall no
17 longer be entitled to receive any delivery service credits
18 for the excess electricity generated by its facility and
19 shall be subject to the provisions of subsection (n) of
20 Section 16-107.5 of this Act unless the owner or operator
21 receives a rebate only for an energy storage device and
22 not for the distributed generation device.
23 (4) To be eligible for a rebate described in this
24 subsection (c), the owner or operator of the distributed
25 generation must have a smart inverter installed and in
26 operation on the distributed generation.

HB5856- 271 -LRB103 40655 LNS 73376 b
1 (d) The Commission shall review the proposed tariff
2authorized by subsection (b) of this Section and may make
3changes to the tariff that are consistent with this Section
4and with the Commission's authority under Article IX of this
5Act, subject to notice and hearing. Following notice and
6hearing, the Commission shall issue an order approving, or
7approving with modification, such tariff no later than 240
8days after the utility files its tariff. Upon the effective
9date of this amendatory Act of the 102nd General Assembly, an
10electric utility shall file a petition with the Commission to
11amend and update any existing tariffs to comply with
12subsections (b) and (c).
13 (e) By no later than June 30, 2023, the Commission shall
14open an independent, statewide investigation into the value
15of, and compensation for, distributed energy resources. The
16Commission shall conduct the investigation, but may arrange
17for experts or consultants independent of the utilities and
18selected by the Commission to assist with the investigation.
19The cost of the investigation shall be shared by the utilities
20filing tariffs under subsection (b) of this Section but may be
21recovered as an expense through normal ratemaking procedures.
22 (1) The Commission shall ensure that the investigation
23 includes, at minimum, diverse sets of stakeholders; a
24 review of best practices in calculating the value of
25 distributed energy resource benefits; a review of the full
26 value of the distributed energy resources and the manner

HB5856- 272 -LRB103 40655 LNS 73376 b
1 in which each component of that value is or is not
2 otherwise compensated; and assessments of how the value of
3 distributed energy resources may evolve based on the
4 present and future technological capabilities of
5 distributed energy resources and based on present and
6 future grid needs.
7 (2) The Commission's final order concluding this
8 investigation shall establish an annual process and
9 formula for the compensation of distributed generation and
10 energy storage systems, and an initial set of inputs for
11 that formula. The Commission's final order concluding this
12 investigation shall establish base rebates that compensate
13 distributed generation, community renewable generation
14 projects and energy storage systems for the system-wide
15 grid services that they provide. Those base rebate values
16 shall be consistent across the state, and shall not vary
17 by customer, customer class, customer location, or any
18 other variable. With respect to rebates for distributed
19 generation or community renewable generation projects,
20 that rebate shall not be lower than $250 per kilowatt of
21 nameplate generating capacity of the distributed
22 generation or community renewable generation project. The
23 Commission's final order concluding this proceeding shall
24 also direct the utilities to update the formula, on an
25 annual basis, with inputs derived from their integrated
26 grid plans developed pursuant to Section 16-105.17. The

HB5856- 273 -LRB103 40655 LNS 73376 b
1 base rebate shall be updated annually based on the annual
2 updates to the formula inputs, but, with respect to
3 rebates for distributed generation or community renewable
4 generation projects, shall be no lower than $250 per
5 kilowatt of nameplate generating capacity of the
6 distributed generation or community renewable generation
7 project.
8 (3) The Commission shall also determine, as a part of
9 its investigation under this subsection, whether
10 distributed energy resources can provide any additive
11 services. Those additive services may include services
12 that are provided through utility-controlled responses to
13 grid conditions. If the Commission determines that
14 distributed energy resources can provide additive grid
15 services, the Commission shall determine the terms and
16 conditions for the operation and compensation of those
17 services. That compensation shall be above and beyond the
18 base rebate that the distributed energy generation,
19 community renewable generation project and energy storage
20 system receives. Compensation for additive services may
21 vary by location, time, performance characteristics,
22 technology types, or other variables.
23 (4) The Commission shall ensure that compensation for
24 distributed energy resources, including base rebates and
25 any payments for additive services, shall reflect all
26 reasonably known and measurable values of the distributed

HB5856- 274 -LRB103 40655 LNS 73376 b
1 generation over its full expected useful life.
2 Compensation for additive services shall reflect, but
3 shall not be limited to, any geographic, time-based,
4 performance-based, and other benefits of distributed
5 generation, as well as the present and future
6 technological capabilities of distributed energy resources
7 and present and future grid needs.
8 (5) The Commission shall consider the electric
9 utility's integrated grid plan developed pursuant to
10 Section 16-105.17 of this Act to help identify the value
11 of distributed energy resources for the purpose of
12 calculating the compensation described in this subsection.
13 (6) The Commission shall determine additional
14 compensation for distributed energy resources that creates
15 savings and value on the distribution system by being
16 co-located or in close proximity to electric vehicle
17 charging infrastructure in use by medium-duty and
18 heavy-duty vehicles, primarily serving environmental
19 justice communities, as outlined in the utility integrated
20 grid planning process under Section 16-105.17 of this Act.
21 No later than 60 days after the Commission enters its
22final order under this subsection (e), each utility shall file
23its updated tariff or tariffs in compliance with the order,
24including new tariffs for the recovery of costs incurred under
25this subsection (e) that shall provide for volumetric-based
26cost recovery, and the Commission shall approve, or approve

HB5856- 275 -LRB103 40655 LNS 73376 b
1with modification, the tariff or tariffs within 240 days after
2the utility's filing.
3 (f) Notwithstanding any provision of this Act to the
4contrary, the owner or operator of a community renewable
5generation project as defined in Section 1-10 of the Illinois
6Power Agency Act shall also be eligible to apply for the rebate
7described in this Section. The owner or operator of the
8community renewable generation project may apply for a rebate
9only if the owner or operator, or previous owner or operator,
10of the community renewable generation project has not already
11submitted an application, and, regardless of whether the
12subscriber is a residential or non-residential customer, may
13be allowed the amount identified in paragraph (1) of
14subsection (c) applicable on the date that the application is
15submitted.
16 (g) The owner of the distributed generation or community
17renewable generation project may apply for the rebate or
18rebates approved under this Section at the time of execution
19of an interconnection agreement with the distribution utility
20and shall receive the value available at that time of
21execution of the interconnection agreement, provided the
22project reaches mechanical completion within 24 months after
23execution of the interconnection agreement. If the project has
24not reached mechanical completion within 24 months after
25execution, the owner may reapply for the rebate or rebates
26approved under this Section available at the time of

HB5856- 276 -LRB103 40655 LNS 73376 b
1application and shall receive the value available at the time
2of application. The utility shall issue the rebate no later
3than 60 days after the project is energized. In the event the
4application is incomplete or the utility is otherwise unable
5to calculate the payment based on the information provided by
6the owner, the utility shall issue the payment no later than 60
7days after the application is complete or all requested
8information is received.
9 (h) An electric utility shall recover from its retail
10customers all of the costs of the rebates made under a tariff
11or tariffs approved under subsection (d) of this Section,
12including, but not limited to, the value of the rebates and all
13costs incurred by the utility to comply with and implement
14subsections (b) and (c) of this Section, but not including
15costs incurred by the utility to comply with and implement
16subsection (e) of this Section, consistent with the following
17provisions:
18 (1) The utility shall defer the full amount of its
19 costs as a regulatory asset. The total costs deferred as a
20 regulatory asset shall be amortized over a 15-year period.
21 The unamortized balance shall be recognized as of December
22 31 for a given year. The utility shall also earn a return
23 on the total of the unamortized balance of the regulatory
24 assets, less any deferred taxes related to the unamortized
25 balance, at an annual rate equal to the utility's weighted
26 average cost of capital that includes, based on a year-end

HB5856- 277 -LRB103 40655 LNS 73376 b
1 capital structure, the utility's actual cost of debt for
2 the applicable calendar year and a cost of equity, which
3 shall be calculated as the sum of (i) the average for the
4 applicable calendar year of the monthly average yields of
5 30-year U.S. Treasury bonds published by the Board of
6 Governors of the Federal Reserve System in its weekly H.15
7 Statistical Release or successor publication; and (ii) 580
8 basis points, including a revenue conversion factor
9 calculated to recover or refund all additional income
10 taxes that may be payable or receivable as a result of that
11 return.
12 When an electric utility creates a regulatory asset
13 under the provisions of this paragraph (1) of subsection
14 (h), the costs are recovered over a period during which
15 customers also receive a benefit, which is in the public
16 interest. Accordingly, it is the intent of the General
17 Assembly that an electric utility that elects to create a
18 regulatory asset under the provisions of this paragraph
19 (1) shall recover all of the associated costs, including,
20 but not limited to, its cost of capital as set forth in
21 this paragraph (1). After the Commission has approved the
22 prudence and reasonableness of the costs that comprise the
23 regulatory asset, the electric utility shall be permitted
24 to recover all such costs, and the value and
25 recoverability through rates of the associated regulatory
26 asset shall not be limited, altered, impaired, or reduced.

HB5856- 278 -LRB103 40655 LNS 73376 b
1 To enable the financing of the incremental capital
2 expenditures, including regulatory assets, for electric
3 utilities that serve less than 3,000,000 retail customers
4 but more than 500,000 retail customers in the State, the
5 utility's actual year-end capital structure that includes
6 a common equity ratio, excluding goodwill, of up to and
7 including 50% of the total capital structure shall be
8 deemed reasonable and used to set rates.
9 (2) The utility, at its election, may recover all of
10 the costs as part of a filing for a general increase in
11 rates under Article IX of this Act, as part of an annual
12 filing to update a performance-based formula rate under
13 subsection (d) of Section 16-108.5 of this Act, or through
14 an automatic adjustment clause tariff, provided that
15 nothing in this paragraph (2) permits the double recovery
16 of such costs from customers. If the utility elects to
17 recover the costs it incurs under subsections (b) and (c)
18 through an automatic adjustment clause tariff, the utility
19 may file its proposed tariff together with the tariff it
20 files under subsection (b) of this Section or at a later
21 time. 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

HB5856- 279 -LRB103 40655 LNS 73376 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) An electric utility shall recover from its retail
18customers, on a volumetric basis, all of the costs of the
19rebates made under a tariff or tariffs placed into effect
20under subsection (e) of this Section, including, but not
21limited to, the value of the rebates and all costs incurred by
22the utility to comply with and implement subsection (e) of
23this 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

HB5856- 280 -LRB103 40655 LNS 73376 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

HB5856- 281 -LRB103 40655 LNS 73376 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

HB5856- 282 -LRB103 40655 LNS 73376 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
11order, or order on rehearing, whichever is later, approving an
12electric utility's proposed tariff under this Section, the
13electric utility shall provide notice of the availability of
14rebates under this Section.
15(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
16 (220 ILCS 5/16-107.9 new)
17 Sec. 16-107.9. Virtual power plant program.
18 (a) In this Section:
19 "Aggregator" means a party, other than the electric
20utility or its affiliate, that (i) represents and aggregates
21the load of participating customers who collectively have the
22ability to deploy 100 kilowatts or more of deployment of
23eligible devices and (ii) is responsible for performance of
24the aggregation in the program.
25 "Distributed energy resources management system" or

HB5856- 283 -LRB103 40655 LNS 73376 b
1"DERMS" means a platform that may be used by distribution
2system operators or utilities to integrate grid resources such
3as distributed energy resources into system operations.
4 "Distributed renewable energy generation device" has the
5meaning set forth in Section 1-10 of the Illinois Power Agency
6Act.
7 "Eligible devices" means a distributed renewable energy
8device paired with one or more energy storage systems.
9 "Energy storage system" has the meaning set forth in
10subsection (a) of Section 16-107.6.
11 "Participating customer" means a retail customer as
12defined in Section 16-102 with one or more eligible devices,
13including a community renewable generation project.
14 "Smart inverter" has the meaning set forth in subsection
15(a) of Section 16-107.6.
16 (b) The General Assembly finds that when eligible devices
17commit to deployment at times of stress on the grid and in
18wholesale energy markets, the actual deployment benefits all
19customers of the utility with enhanced reliability and
20protection from wholesale price increases and that those
21socialized goods should be encouraged and compensated.
22 (c) Within 60 days after the effective date of this
23amendatory Act of the 103rd General Assembly, each electric
24utility serving more than 300,000 customers as of January 1,
252023, shall propose an initial tariff. The initial tariff
26shall be consistent with the following:

HB5856- 284 -LRB103 40655 LNS 73376 b
1 (1) Each request by the utility for an aggregator or
2 participating customer to deploy eligible devices to the
3 level identified in advance by the aggregator or
4 participating customer shall be an event.
5 (2) In exchange for an aggregator facilitating the
6 dispatch of eligible systems during hours identified by
7 the utility under this tariff or a participating customer
8 not using an aggregator dispatching, with each time period
9 being an event, not to exceed 60 hours in a calendar year
10 and not to exceed 2 consecutive hours, the utility shall,
11 at the end of each delivery year during which an
12 aggregator participates, compensate the aggregator in an
13 amount per kilowatt multiplied by the average number of
14 kilowatts discharged during events in a delivery year by
15 those eligible systems enrolled with the aggregator, with
16 the amount per kilowatt to be determined by the
17 Commission. Discharge shall be measured by the total power
18 and energy measured by the inverter of the eligible device
19 and shall not distinguish between power and energy from
20 the distributed renewable energy generation device or the
21 energy storage system. In determining the value of the
22 performance payment, the Commission shall, at minimum,
23 consider the benefits to the utility and ratepayers of
24 peak remediation, reduced capacity and transmission
25 allocations to the applicable regional transmission
26 organization zone, and a reasonable estimation of the

HB5856- 285 -LRB103 40655 LNS 73376 b
1 value of reduced transmission investment and other grid
2 services not compensated by tariffs authorized under
3 Section 16-107.6. The value shall be set to encourage
4 robust participation and shall be for a term of no less
5 than 5 years. At no time shall the compensation per
6 average kilowatt of demand reduction delivered be less
7 than $250.
8 (3) An aggregator or participating customer applying
9 individually must represent that it has identified for
10 participation one or more eligible devices with an
11 aggregate export capacity of at least 100 kilowatts or any
12 greater amount. Nothing in the tariff shall require a
13 particular participating customer using an aggregator
14 deploy at any particular time.
15 (4) The utility shall not send or receive signals
16 directly to or from any participating customer represented
17 by an aggregator for an event under the virtual power
18 plant program described in this Section.
19 (5) The aggregator may have capabilities to receive
20 dispatch signals from utilities or utility-contracted
21 DERMS providers through communication protocols, such as
22 IEEE 2030.5 or OpenADR, or through other protocol as the
23 Commission may approve. To facilitate adoption and
24 participation, the utility must also provide dispatch
25 signals in the form of an email or mutually agreeable
26 implementation.

HB5856- 286 -LRB103 40655 LNS 73376 b
1 (6) Notwithstanding anything to the contrary, nothing
2 prohibits a participating customer from simultaneously
3 being a participating customer and taking service under
4 tariffs authorized by Section 16-107.5 or 16-107.6.
5 (7) A participating customer may enroll in the virtual
6 power plant program directly if eligible or through an
7 aggregator for one or more years, and the electric utility
8 shall not set a minimum or maximum length of participation
9 for an eligible system represented by an aggregator. The
10 utility shall not limit the number of participating
11 customers nor shall any customer be prohibited from
12 participating due to its rate class.
13 (8) The electric utility may include reasonable
14 requirements for participation consistent with this
15 subsection except that the utility may not require
16 collateral from a participating customer or an aggregator
17 and neither the utility nor entities with which the
18 utility shares a common parent may be an aggregator. In no
19 event may the electric utility call an event with less
20 than 24 hours' prior notice and in no event may one or more
21 events on a single calendar day total more than 2 hours.
22 The electric utility shall not penalize a participating
23 customer or aggregator for a participating customer
24 exporting during an event, and the electric utility shall
25 not require preapproval for customer export during an
26 event.

HB5856- 287 -LRB103 40655 LNS 73376 b
1 (9) The utility shall recover the costs of the virtual
2 power plant program through delivery rates, including
3 delivery rates authorized by the Multi-Year Rate Plan.
4 (d) The Commission shall approve or approve with
5modifications the tariff filed by each utility pursuant to
6subsection (c) within 240 days after its filing by the
7utility. At any time, the utility may propose revisions to the
8initial tariff or any revisions to those revisions, and the
9Commission shall approve such revisions if, in addition to
10requirements under Article IX, such revisions are consistent
11with the requirements of this Section.
12 (e) Not more than 6 months after 2 full delivery years of
13operation of the tariffs authorized in this Section, the
14Commission shall issue a report to the General Assembly
15assessing the value and efficacy of the virtual power plant
16program, including proposals for expansions or modifications.
17 (f) Nothing in the virtual power plant program shall
18either prevent the participating customer from participating,
19directly or through a third-party aggregator, in any other
20program, including any program required or authorized by
21Section 16-107.5 or 16-107.6, or impair the entitlement of any
22participating customer to benefits authorized to the
23participating customer by Section 16-107.5.
24 (g) The Commission may consider providing compensation to
25aggregators or participating customers not using an aggregator
26to the extent that the aggregators' participating customers or

HB5856- 288 -LRB103 40655 LNS 73376 b
1participating customers not using an aggregator are located in
2equity investment eligible communities, as that term is
3defined in Section 1-10 of the Illinois Power Agency Act.
4 (h) The tariffs approved by the Commission shall not
5reflect any additional charges, fees, or insurance
6requirements imposed on those owning or operating distributed
7renewable energy generation devices, distributed energy
8resources, or energy storage systems beyond those imposed on
9similarly situated customers that do not own or operate these
10resources.
11 (i) If a utility issuing a tariff under this Section
12conducts measurement and verification prescribed by the
13Commission, notwithstanding anything to the contrary all
14discharge from distributed renewable generation devices taking
15service under the tariff shall be counted towards the
16utility's peak load reduction performance metric authorized by
17item (ii) of subparagraph (A) of paragraph (2) of subsection
18(e) of Section 16-108.18. The Commission shall not require an
19eligible system to participate in any capacity or demand
20response markets or programs as a condition of the load
21reduction attributable to participating systems to count
22toward the utility's peak load reduction performance metric.
23 (220 ILCS 5/16-107.10 new)
24 Sec. 16-107.10. Peak remediation program.
25 (a) In this Section:

HB5856- 289 -LRB103 40655 LNS 73376 b
1 "Community renewable generation project" has the meaning
2set forth in Section 1-10 of the Illinois Power Agency Act.
3 "Defined discharge hours" means the defined hours in the
4initial tariff or subsequent tariffs that an eligible device
5is eligible to receive a peak discharge payment per
6kilowatt-hour of energy discharged.
7 "Eligible device" means a community renewable generation
8project paired with one or more energy storage systems.
9 "Energy storage system" has the meaning set forth in
10subsection (a) of Section 16-107.6.
11 "Nameplate capacity" has the meaning set forth in Section
121-10 of the Illinois Power Agency Act.
13 "Peak discharge payment" means a price per kilowatt hour
14paid for energy discharged from an eligible device during the
15defined discharge hours.
16 "Threshold date" has the meaning set forth in subsection
17(a) of Section 16-107.6.
18 (b) The General Assembly finds that the electric grid sees
19high demand for electricity but fewer renewable resources
20available to meet that high demand. The General Assembly
21further finds that all ratepayers benefit from deployment of
22energy storage in a way that alleviates stress on the grid and
23reduces the costs for ratepayers frequently allocated during
24those peak hours.
25 (c) Within 90 days after the effective date of this
26amendatory Act of the 103rd General Assembly, each electric

HB5856- 290 -LRB103 40655 LNS 73376 b
1utility serving more than 300,000 retail customers as of
2January 1, 2023 shall propose an initial tariff. The initial
3tariff shall be consistent with the following:
4 (1) The utility shall compensate eligible devices with
5 a nameplate capacity of at least 100 kilowatts but no more
6 than 5,000 kilowatts for discharging into the grid during
7 defined discharge hours.
8 (2) The defined discharge hours shall be the hours of
9 4 p.m. through 8 p.m. on days during the months of June,
10 July, August, and September.
11 (3) In exchange for generating and providing through
12 its meter to the utility's distribution system at least 50
13 kilowatts during defined discharge hours, the utility
14 shall compensate the owner or operator of the eligible
15 device or a third party designated by the owner or
16 operator of the eligible device a peak discharge payment
17 in an amount to be determined by the Commission in
18 proportion to the average discharge during the hours
19 according to a pre-defined per kilowatt average discharge
20 payment. Discharge shall be measured by the total power
21 and energy measured by the inverter of the eligible device
22 and shall not distinguish between power and energy from
23 the distributed renewable energy generation device or the
24 energy storage system.
25 (4) In determining the value of the peak discharge
26 payment for each participating utility, the Commission

HB5856- 291 -LRB103 40655 LNS 73376 b
1 shall, at minimum, consider the benefits to the utility
2 and ratepayers of peak remediation, reduced capacity, and
3 transmission allocations to the applicable regional
4 transmission organization zone, and a reasonable
5 estimation of the value of reduced transmission investment
6 and other grid services not compensated by tariffs
7 authorized under Section 16-107.6. The value shall be set
8 to encourage robust participation and shall be for a term
9 of no less than 15 years. The utility shall not limit the
10 number or capacity of participating devices.
11 (5) The electric utility may include reasonable
12 requirements for participation consistent with this
13 subsection except that the utility may not require
14 collateral from the owner or operator of a participating
15 eligible device.
16 (6) Nothing in the tariff or this Section shall
17 separately or independently authorize the utility to
18 control deployment of the storage device.
19 (7) The utility shall recover the costs incurred under
20 the tariff through delivery rates, including delivery
21 rates authorized by the Multi-Year Rate Plan.
22 (d) The Commission shall approve or approve with
23modifications the initial tariff filed by each utility
24pursuant to subsection (c) within 240 days after filing by the
25utility. At any time, the utility may propose revisions to the
26initial tariff or any revisions to those revisions, and the

HB5856- 292 -LRB103 40655 LNS 73376 b
1Commission shall approve such revisions if, in addition to
2requirements under Article IX, such revisions are consistent
3with the requirements of this Section.
4 (e) After the threshold date, the utility shall file an
5annual petition to update the initial tariff for eligible
6systems that begin to take service under the tariff during the
7annual period. The utility shall be allowed to update the peak
8discharge payment and defined discharge hours, which shall not
9begin earlier than 4 p.m., but must otherwise meet all the
10requirements under subsection (c). The Commission shall
11approve the petition to update the initial tariff within 90
12days after the petition is filed.
13 (f) Nothing in this Section, including any rule,
14regulation, or tariff authorized by this Section, shall
15prevent the eligible device or any component of the eligible
16device from participating in any program required or
17authorized by Section 16-107.6, nor shall it impair the
18entitlement of any participating customer to benefits
19authorized by Section 16-107.5.
20 (g) The tariffs approved by the Commission shall not
21reflect any additional charges, fees, or insurance
22requirements imposed on those owning or operating distributed
23renewable energy generation device, distributed energy
24resources, or energy storage system beyond those imposed on
25similarly situated customers that do not own or operate these
26resources.

HB5856- 293 -LRB103 40655 LNS 73376 b
1 (h) If a utility issuing a tariff under this Section
2conducts measurement and verification prescribed by the
3Commission, notwithstanding anything to the contrary, all
4discharge from community renewable generation projects taking
5service under the tariff shall be counted toward the utility's
6peak load reduction performance metric authorized by item (ii)
7of subparagraph (A) of paragraph (2) of subsection (e) of
8Section 16-108.18. The Commission shall not require an
9eligible system to participate in any capacity or demand
10response markets or programs as a condition of the load
11reduction attributable to participating systems to count
12toward the utility's peak load reduction performance metric.
13 (220 ILCS 5/16-107.11 new)
14 Sec. 16-107.11. Stand-alone energy storage distribution
15deployment program.
16 (a) In this Section:
17 "Eligible device" means a stand-alone energy storage
18system.
19 "Paired" means an energy storage system is charged with
20electricity generated by a distribution generation device or
21community renewable generation project.
22 "Program" means the stand-alone energy storage
23distribution deployment program.
24 "Stand-alone energy storage system" means an energy
25storage system that is not paired with a distributed

HB5856- 294 -LRB103 40655 LNS 73376 b
1generation device or a community renewable generation project
2and may be interconnected on the customer's side or the
3utility's side of a customer's meter, but shall be
4interconnected under subsection (h) of Section 16-107.5.
5 (b) The General Assembly finds that energy storage devices
6interconnected to the distribution grid, including behind
7customer meters, can provide unique values and benefits to
8electric ratepayers in Illinois. Energy storage does not need
9to be paired with a renewable generation device to provide
10values and benefits. Vulnerable urban areas may be less able
11to support renewable generation deployments due to land, roof,
12or other constraints. A well-designed stand-alone energy
13storage deployment program can benefit electric customers by
14alleviating stress on distribution grid infrastructure,
15deferring or avoiding costly distribution grid investments,
16increasing the resilience and reliability of the electric
17distribution grid, reducing outages, avoiding health and
18welfare risks to vulnerable populations, and providing energy
19and capacity during times of high demand, resulting in lower
20costs overall.
21 (c) Within 60 days after the effective date of this
22amendatory Act of the 103rd General Assembly, the Commission
23shall establish a working group with relevant stakeholders to
24develop a stand-alone energy storage distribution deployment
25program. The program shall be designed to compensate
26front-of-meter and back-of-meter energy storage devices

HB5856- 295 -LRB103 40655 LNS 73376 b
1deployed on the distribution grid for the value the storage
2devices provide for Illinois ratepayers.
3 (d) Each utility serving more than 100,000 retail
4customers on January 1, 2023 shall file with the Commission,
5no more than 210 days after the effective date of this
6amendatory Act of the 103rd General Assembly, a tariff
7implementing the requirements of this subsection. The
8Commission shall consider the final report of the working
9group and modify the tariffs so that they comply with this
10Section and the working group's report. A tariff for
11compensation of stand-alone energy storage systems shall be
12made available for no less than 20 years and shall allow for
13stacked revenues to reflect the spectrum of values provided by
14participating devices. The resulting revenue model shall be
15financeable and provide for robust deployment in locations
16that improve reliability in vulnerable urban, suburban, and
17rural communities throughout the State. The compensation
18structure for deploying stand-alone energy storage systems
19shall include, but shall not be limited to, capacity and
20transmission value, energy value, system-wide resilience and
21reliability benefits, and distribution value, including the
22value equivalent to the location's marginal cost of
23distribution service, that shall include avoided future
24distribution grid capital investments and operation and
25maintenance costs and shall be updated at least annually. The
26compensation structure shall consider additional benefits to

HB5856- 296 -LRB103 40655 LNS 73376 b
1the distribution grid in specific locations where the grid and
2communities are particularly vulnerable to disruptions,
3including location-specific reliability and resilience
4benefits, distribution voltage, and power quality benefits.
5The values shall be examined on a substation and feeder level.
6For purposes of this subsection, "vulnerable communities"
7means communities that suffer from lower-than-average electric
8reliability indicators, including, but not limited to, SAFI,
9CADI, CEMI, as identified by the Commission, in consultation
10with the utilities.
11 (e) Each tariff applies to stand-alone energy storage
12systems interconnected to the distribution grid and purchasing
13certain services from the utility.
14 (f) The tariffs shall account for operational parameters
15of participating systems and advantage off-peak charging
16through dynamic pricing. Distribution rates shall be
17non-discriminatory and designed to recoup the distribution
18company's net costs in a manner similar to how they are
19incurred by the distribution company, in consideration of
20project sponsor-funded interconnection upgrades and without
21unduly impeding the participation of energy storage systems.
22 (g) To the extent required, each utility filing a tariff
23under this Section shall provide the Commission with notice of
24its intent to promptly file with the Federal Energy Regulatory
25Commission a wholesale distribution service rate schedule to
26apply to standalone energy storage systems that are

HB5856- 297 -LRB103 40655 LNS 73376 b
1interconnected to their distribution network but are
2transacting in PJM or MISO's wholesale electricity markets, as
3applicable.
4 (h) Participation in the program shall not prohibit an
5energy storage system from selling non-duplicative products
6and services in a wholesale market.
7 (220 ILCS 5/16-108)
8 Sec. 16-108. Recovery of costs associated with the
9provision of delivery and other services.
10 (a) An electric utility shall file a delivery services
11tariff with the Commission at least 210 days prior to the date
12that it is required to begin offering such services pursuant
13to this Act. An electric utility shall provide the components
14of delivery services that are subject to the jurisdiction of
15the Federal Energy Regulatory Commission at the same prices,
16terms and conditions set forth in its applicable tariff as
17approved or allowed into effect by that Commission. The
18Commission shall otherwise have the authority pursuant to
19Article IX to review, approve, and modify the prices, terms
20and conditions of those components of delivery services not
21subject to the jurisdiction of the Federal Energy Regulatory
22Commission, including the authority to determine the extent to
23which such delivery services should be offered on an unbundled
24basis. In making any such determination the Commission shall
25consider, at a minimum, the effect of additional unbundling on

HB5856- 298 -LRB103 40655 LNS 73376 b
1(i) the objective of just and reasonable rates, (ii) electric
2utility employees, and (iii) the development of competitive
3markets for electric energy services in Illinois.
4 (b) The Commission shall enter an order approving, or
5approving as modified, the delivery services tariff no later
6than 30 days prior to the date on which the electric utility
7must commence offering such services. The Commission may
8subsequently modify such tariff pursuant to this Act.
9 (c) The electric utility's tariffs shall define the
10classes of its customers for purposes of delivery services
11charges. Delivery services shall be priced and made available
12to all retail customers electing delivery services in each
13such class on a nondiscriminatory basis regardless of whether
14the retail customer chooses the electric utility, an affiliate
15of the electric utility, or another entity as its supplier of
16electric power and energy. Charges for delivery services shall
17be cost based, and shall allow the electric utility to recover
18the costs of providing delivery services through its charges
19to its delivery service customers that use the facilities and
20services associated with such costs. Such costs shall include
21the costs of owning, operating and maintaining transmission
22and distribution facilities. The Commission shall also be
23authorized to consider whether, and if so to what extent, the
24following costs are appropriately included in the electric
25utility's delivery services rates: (i) the costs of that
26portion of generation facilities used for the production and

HB5856- 299 -LRB103 40655 LNS 73376 b
1absorption of reactive power in order that retail customers
2located in the electric utility's service area can receive
3electric power and energy from suppliers other than the
4electric utility, and (ii) the costs associated with the use
5and redispatch of generation facilities to mitigate
6constraints on the transmission or distribution system in
7order that retail customers located in the electric utility's
8service area can receive electric power and energy from
9suppliers other than the electric utility. Nothing in this
10subsection shall be construed as directing the Commission to
11allocate any of the costs described in (i) or (ii) that are
12found to be appropriately included in the electric utility's
13delivery services rates to any particular customer group or
14geographic area in setting delivery services rates.
15 (d) The Commission shall establish charges, terms and
16conditions for delivery services that are just and reasonable
17and shall take into account customer impacts when establishing
18such charges. In establishing charges, terms and conditions
19for delivery services, the Commission shall take into account
20voltage level differences. A retail customer shall have the
21option to request to purchase electric service at any delivery
22service voltage reasonably and technically feasible from the
23electric facilities serving that customer's premises provided
24that there are no significant adverse impacts upon system
25reliability or system efficiency. A retail customer shall also
26have the option to request to purchase electric service at any

HB5856- 300 -LRB103 40655 LNS 73376 b
1point of delivery that is reasonably and technically feasible
2provided that there are no significant adverse impacts on
3system reliability or efficiency. Such requests shall not be
4unreasonably denied.
5 (e) Electric utilities shall recover the costs of
6installing, operating or maintaining facilities for the
7particular benefit of one or more delivery services customers,
8including without limitation any costs incurred in complying
9with a customer's request to be served at a different voltage
10level, directly from the retail customer or customers for
11whose benefit the costs were incurred, to the extent such
12costs are not recovered through the charges referred to in
13subsections (c) and (d) of this Section.
14 (f) An electric utility shall be entitled but not required
15to implement transition charges in conjunction with the
16offering of delivery services pursuant to Section 16-104. If
17an electric utility implements transition charges, it shall
18implement such charges for all delivery services customers and
19for all customers described in subsection (h), but shall not
20implement transition charges for power and energy that a
21retail customer takes from cogeneration or self-generation
22facilities located on that retail customer's premises, if such
23facilities meet the following criteria:
24 (i) the cogeneration or self-generation facilities
25 serve a single retail customer and are located on that
26 retail customer's premises (for purposes of this

HB5856- 301 -LRB103 40655 LNS 73376 b
1 subparagraph and subparagraph (ii), an industrial or
2 manufacturing retail customer and a third party contractor
3 that is served by such industrial or manufacturing
4 customer through such retail customer's own electrical
5 distribution facilities under the circumstances described
6 in subsection (vi) of the definition of "alternative
7 retail electric supplier" set forth in Section 16-102,
8 shall be considered a single retail customer);
9 (ii) the cogeneration or self-generation facilities
10 either (A) are sized pursuant to generally accepted
11 engineering standards for the retail customer's electrical
12 load at that premises (taking into account standby or
13 other reliability considerations related to that retail
14 customer's operations at that site) or (B) if the facility
15 is a cogeneration facility located on the retail
16 customer's premises, the retail customer is the thermal
17 host for that facility and the facility has been designed
18 to meet that retail customer's thermal energy requirements
19 resulting in electrical output beyond that retail
20 customer's electrical demand at that premises, comply with
21 the operating and efficiency standards applicable to
22 "qualifying facilities" specified in title 18 Code of
23 Federal Regulations Section 292.205 as in effect on the
24 effective date of this amendatory Act of 1999;
25 (iii) the retail customer on whose premises the
26 facilities are located either has an exclusive right to

HB5856- 302 -LRB103 40655 LNS 73376 b
1 receive, and corresponding obligation to pay for, all of
2 the electrical capacity of the facility, or in the case of
3 a cogeneration facility that has been designed to meet the
4 retail customer's thermal energy requirements at that
5 premises, an identified amount of the electrical capacity
6 of the facility, over a minimum 5-year period; and
7 (iv) if the cogeneration facility is sized for the
8 retail customer's thermal load at that premises but
9 exceeds the electrical load, any sales of excess power or
10 energy are made only at wholesale, are subject to the
11 jurisdiction of the Federal Energy Regulatory Commission,
12 and are not for the purpose of circumventing the
13 provisions of this subsection (f).
14If a generation facility located at a retail customer's
15premises does not meet the above criteria, an electric utility
16implementing transition charges shall implement a transition
17charge until December 31, 2006 for any power and energy taken
18by such retail customer from such facility as if such power and
19energy had been delivered by the electric utility. Provided,
20however, that an industrial retail customer that is taking
21power from a generation facility that does not meet the above
22criteria but that is located on such customer's premises will
23not be subject to a transition charge for the power and energy
24taken by such retail customer from such generation facility if
25the facility does not serve any other retail customer and
26either was installed on behalf of the customer and for its own

HB5856- 303 -LRB103 40655 LNS 73376 b
1use prior to January 1, 1997, or is both predominantly fueled
2by byproducts of such customer's manufacturing process at such
3premises and sells or offers an average of 300 megawatts or
4more of electricity produced from such generation facility
5into the wholesale market. Such charges shall be calculated as
6provided in Section 16-102, and shall be collected on each
7kilowatt-hour delivered under a delivery services tariff to a
8retail customer from the date the customer first takes
9delivery services until December 31, 2006 except as provided
10in subsection (h) of this Section. Provided, however, that an
11electric utility, other than an electric utility providing
12service to at least 1,000,000 customers in this State on
13January 1, 1999, shall be entitled to petition for entry of an
14order by the Commission authorizing the electric utility to
15implement transition charges for an additional period ending
16no later than December 31, 2008. The electric utility shall
17file its petition with supporting evidence no earlier than 16
18months, and no later than 12 months, prior to December 31,
192006. The Commission shall hold a hearing on the electric
20utility's petition and shall enter its order no later than 8
21months after the petition is filed. The Commission shall
22determine whether and to what extent the electric utility
23shall be authorized to implement transition charges for an
24additional period. The Commission may authorize the electric
25utility to implement transition charges for some or all of the
26additional period, and shall determine the mitigation factors

HB5856- 304 -LRB103 40655 LNS 73376 b
1to be used in implementing such transition charges; provided,
2that the Commission shall not authorize mitigation factors
3less than 110% of those in effect during the 12 months ended
4December 31, 2006. In making its determination, the Commission
5shall consider the following factors: the necessity to
6implement transition charges for an additional period in order
7to maintain the financial integrity of the electric utility;
8the prudence of the electric utility's actions in reducing its
9costs since the effective date of this amendatory Act of 1997;
10the ability of the electric utility to provide safe, adequate
11and reliable service to retail customers in its service area;
12and the impact on competition of allowing the electric utility
13to implement transition charges for the additional period.
14 (g) The electric utility shall file tariffs that establish
15the transition charges to be paid by each class of customers to
16the electric utility in conjunction with the provision of
17delivery services. The electric utility's tariffs shall define
18the classes of its customers for purposes of calculating
19transition charges. The electric utility's tariffs shall
20provide for the calculation of transition charges on a
21customer-specific basis for any retail customer whose average
22monthly maximum electrical demand on the electric utility's
23system during the 6 months with the customer's highest monthly
24maximum electrical demands equals or exceeds 3.0 megawatts for
25electric utilities having more than 1,000,000 customers, and
26for other electric utilities for any customer that has an

HB5856- 305 -LRB103 40655 LNS 73376 b
1average monthly maximum electrical demand on the electric
2utility's system of one megawatt or more, and (A) for which
3there exists data on the customer's usage during the 3 years
4preceding the date that the customer became eligible to take
5delivery services, or (B) for which there does not exist data
6on the customer's usage during the 3 years preceding the date
7that the customer became eligible to take delivery services,
8if in the electric utility's reasonable judgment there exists
9comparable usage information or a sufficient basis to develop
10such information, and further provided that the electric
11utility can require customers for which an individual
12calculation is made to sign contracts that set forth the
13transition charges to be paid by the customer to the electric
14utility pursuant to the tariff.
15 (h) An electric utility shall also be entitled to file
16tariffs that allow it to collect transition charges from
17retail customers in the electric utility's service area that
18do not take delivery services but that take electric power or
19energy from an alternative retail electric supplier or from an
20electric utility other than the electric utility in whose
21service area the customer is located. Such charges shall be
22calculated, in accordance with the definition of transition
23charges in Section 16-102, for the period of time that the
24customer would be obligated to pay transition charges if it
25were taking delivery services, except that no deduction for
26delivery services revenues shall be made in such calculation,

HB5856- 306 -LRB103 40655 LNS 73376 b
1and usage data from the customer's class shall be used where
2historical usage data is not available for the individual
3customer. The customer shall be obligated to pay such charges
4on a lump sum basis on or before the date on which the customer
5commences to take service from the alternative retail electric
6supplier or other electric utility, provided, that the
7electric utility in whose service area the customer is located
8shall offer the customer the option of signing a contract
9pursuant to which the customer pays such charges ratably over
10the period in which the charges would otherwise have applied.
11 (i) An electric utility shall be entitled to add to the
12bills of delivery services customers charges pursuant to
13Sections 9-221, 9-222 (except as provided in Section 9-222.1),
14and Section 16-114 of this Act, Section 5-5 of the Electricity
15Infrastructure Maintenance Fee Law, Section 6-5 of the
16Renewable Energy, Energy Efficiency, and Coal Resources
17Development Law of 1997, and Section 13 of the Energy
18Assistance Act.
19 (i-5) An electric utility required to impose the Coal to
20Solar and Energy Storage Initiative Charge provided for in
21subsection (c-5) of Section 1-75 of the Illinois Power Agency
22Act shall add such charge to the bills of its delivery services
23customers pursuant to the terms of a tariff conforming to the
24requirements of subsection (c-5) of Section 1-75 of the
25Illinois Power Agency Act and this subsection (i-5) and filed
26with and approved by the Commission. The electric utility

HB5856- 307 -LRB103 40655 LNS 73376 b
1shall file its proposed tariff with the Commission on or
2before July 1, 2022 to be effective, after review and approval
3or modification by the Commission, beginning January 1, 2023.
4On or before December 1, 2022, the Commission shall review the
5electric utility's proposed tariff, including by conducting a
6docketed proceeding if deemed necessary by the Commission, and
7shall approve the proposed tariff or direct the electric
8utility to make modifications the Commission finds necessary
9for the tariff to conform to the requirements of subsection
10(c-5) of Section 1-75 of the Illinois Power Agency Act and this
11subsection (i-5). The electric utility's tariff shall provide
12for imposition of the Coal to Solar and Energy Storage
13Initiative Charge on a per-kilowatthour basis to all
14kilowatthours delivered by the electric utility to its
15delivery services customers. The tariff shall provide for the
16calculation of the Coal to Solar and Energy Storage Initiative
17Charge to be in effect for the year beginning January 1, 2023
18and each year beginning January 1 thereafter, sufficient to
19collect the electric utility's estimated payment obligations
20for the delivery year beginning the following June 1 under
21contracts for purchase of renewable energy credits entered
22into pursuant to subsection (c-5) of Section 1-75 of the
23Illinois Power Agency Act and the obligations of the
24Department of Commerce and Economic Opportunity, or any
25successor department or agency, which for purposes of this
26subsection (i-5) shall be referred to as the Department, to

HB5856- 308 -LRB103 40655 LNS 73376 b
1make grant payments during such delivery year from the Coal to
2Solar and Energy Storage Initiative Fund pursuant to grant
3contracts entered into pursuant to subsection (c-5) of Section
41-75 of the Illinois Power Agency Act, and using the electric
5utility's kilowatthour deliveries to its delivery services
6customers during the delivery year ended May 31 of the
7preceding calendar year. On or before November 1 of each year
8beginning November 1, 2022, the Department shall notify the
9electric utilities of the amount of the Department's estimated
10obligations for grant payments during the delivery year
11beginning the following June 1 pursuant to grant contracts
12entered into pursuant to subsection (c-5) of Section 1-75 of
13the Illinois Power Agency Act; and each electric utility shall
14incorporate in the calculation of its Coal to Solar and Energy
15Storage Initiative Charge the fractional portion of the
16Department's estimated obligations equal to the electric
17utility's kilowatthour deliveries to its delivery services
18customers in the delivery year ended the preceding May 31
19divided by the aggregate deliveries of both electric utilities
20to delivery services customers in such delivery year. The
21electric utility shall remit on a monthly basis to the State
22Treasurer, for deposit in the Coal to Solar and Energy Storage
23Initiative Fund provided for in subsection (c-5) of Section
241-75 of the Illinois Power Agency Act, the electric utility's
25collections of the Coal to Solar and Energy Storage Initiative
26Charge estimated to be needed by the Department for grant

HB5856- 309 -LRB103 40655 LNS 73376 b
1payments pursuant to grant contracts entered into pursuant to
2subsection (c-5) of Section 1-75 of the Illinois Power Agency
3Act. The initial charge under the electric utility's tariff
4shall be effective for kilowatthours delivered beginning
5January 1, 2023, and thereafter shall be revised to be
6effective January 1, 2024 and each January 1 thereafter, based
7on the payment obligations for the delivery year beginning the
8following June 1. The tariff shall provide for the electric
9utility to make an annual filing with the Commission on or
10before November 15 of each year, beginning in 2023, setting
11forth the Coal to Solar and Energy Storage Initiative Charge
12to be in effect for the year beginning the following January 1.
13The electric utility's tariff shall also provide that the
14electric utility shall make a filing with the Commission on or
15before August 1 of each year beginning in 2024 setting forth a
16reconciliation, for the delivery year ended the preceding May
1731, of the electric utility's collections of the Coal to Solar
18and Energy Storage Initiative Charge against actual payments
19for renewable energy credits pursuant to contracts entered
20into, and the actual grant payments by the Department pursuant
21to grant contracts entered into, pursuant to subsection (c-5)
22of Section 1-75 of the Illinois Power Agency Act. The tariff
23shall provide that any excess or shortfall of collections to
24payments shall be deducted from or added to, on a
25per-kilowatthour basis, the Coal to Solar and Energy Storage
26Initiative Charge, over the 6-month period beginning October 1

HB5856- 310 -LRB103 40655 LNS 73376 b
1of that calendar year.
2 (j) If a retail customer that obtains electric power and
3energy from cogeneration or self-generation facilities
4installed for its own use on or before January 1, 1997,
5subsequently takes service from an alternative retail electric
6supplier or an electric utility other than the electric
7utility in whose service area the customer is located for any
8portion of the customer's electric power and energy
9requirements formerly obtained from those facilities
10(including that amount purchased from the utility in lieu of
11such generation and not as standby power purchases, under a
12cogeneration displacement tariff in effect as of the effective
13date of this amendatory Act of 1997), the transition charges
14otherwise applicable pursuant to subsections (f), (g), or (h)
15of this Section shall not be applicable in any year to that
16portion of the customer's electric power and energy
17requirements formerly obtained from those facilities,
18provided, that for purposes of this subsection (j), such
19portion shall not exceed the average number of kilowatt-hours
20per year obtained from the cogeneration or self-generation
21facilities during the 3 years prior to the date on which the
22customer became eligible for delivery services, except as
23provided in subsection (f) of Section 16-110.
24 (k) The electric utility shall be entitled to recover
25through tariffed charges all of the costs associated with the
26purchase of zero emission credits from zero emission

HB5856- 311 -LRB103 40655 LNS 73376 b
1facilities to meet the requirements of subsection (d-5) of
2Section 1-75 of the Illinois Power Agency Act and all of the
3costs associated with the purchase of carbon mitigation
4credits from carbon-free energy resources to meet the
5requirements of subsection (d-10) of Section 1-75 of the
6Illinois Power Agency Act. Such costs shall include the costs
7of procuring the zero emission credits and carbon mitigation
8credits from carbon-free energy resources, as well as the
9reasonable costs that the utility incurs as part of the
10procurement processes and to implement and comply with plans
11and processes approved by the Commission under subsections
12(d-5) and (d-10). The costs shall be allocated across all
13retail customers through a single, uniform cents per
14kilowatt-hour charge applicable to all retail customers, which
15shall appear as a separate line item on each customer's bill.
16Beginning June 1, 2017, the electric utility shall be entitled
17to recover through tariffed charges all of the costs
18associated with the purchase of renewable energy resources to
19meet the renewable energy resource standards of subsection (c)
20of Section 1-75 of the Illinois Power Agency Act, under
21procurement plans as approved in accordance with that Section
22and Section 16-111.5 of this Act. Such costs shall include the
23costs of procuring the renewable energy resources, as well as
24the reasonable costs that the utility incurs as part of the
25procurement processes and to implement and comply with plans
26and processes approved by the Commission under such Sections.

HB5856- 312 -LRB103 40655 LNS 73376 b
1The costs associated with the purchase of renewable energy
2resources shall be allocated across all retail customers in
3proportion to the amount of renewable energy resources the
4utility procures for such customers through a single, uniform
5cents per kilowatt-hour charge applicable to such retail
6customers, which shall appear as a separate line item on each
7such customer's bill. The credits, costs, and penalties
8associated with the self-direct renewable portfolio standard
9compliance program described in subparagraph (R) of paragraph
10(1) of subsection (c) of Section 1-75 of the Illinois Power
11Agency Act shall be allocated to approved eligible self-direct
12customers by the utility in a cents per kilowatt-hour credit,
13cost, or penalty, which shall appear as a separate line item on
14each such customer's bill.
15 Beginning on June 1, 2024, the electric utility shall be
16entitled to recover through tariffed charges all of the costs
17associated with the purchase of energy storage credits to meet
18the energy storage standards of Section 1-93 of the Illinois
19Power Agency Act under procurement plans approved in
20accordance with that Section and Section 16-111.5. The costs
21shall include the costs of procuring the energy storage
22credits and the reasonable costs that the utility incurs as
23part of the procurement processes and implementing and
24complying with plans and processes approved by the Commission.
25The costs associated with the purchase of energy storage
26credits shall be allocated across all retail customers in

HB5856- 313 -LRB103 40655 LNS 73376 b
1proportion to the amount of energy storage credits the
2electric utility procures for the customers through a single,
3uniform cents per kilowatt-hour charge applicable to the
4retail customers, that shall appear as a separate line item on
5each customer's bill.
6 Notwithstanding whether the Commission has approved the
7initial long-term renewable resources procurement plan as of
8June 1, 2017, an electric utility shall place new tariffed
9charges into effect beginning with the June 2017 monthly
10billing period, to the extent practicable, to begin recovering
11the costs of procuring renewable energy resources, as those
12charges are calculated under the limitations described in
13subparagraph (E) of paragraph (1) of subsection (c) of Section
141-75 of the Illinois Power Agency Act. Notwithstanding the
15date on which the utility places such new tariffed charges
16into effect, the utility shall be permitted to collect the
17charges under such tariff as if the tariff had been in effect
18beginning with the first day of the June 2017 monthly billing
19period. For the delivery years commencing June 1, 2017, June
201, 2018, June 1, 2019, and each delivery year thereafter, the
21electric utility shall deposit into a separate interest
22bearing account of a financial institution the monies
23collected under the tariffed charges. Money collected from
24customers for the procurement of renewable energy resources in
25a given delivery year may be spent by the utility for the
26procurement of renewable resources over any of the following 5

HB5856- 314 -LRB103 40655 LNS 73376 b
1delivery years, after which unspent money shall be credited
2back to retail customers. The electric utility shall spend all
3money collected in earlier delivery years that has not yet
4been returned to customers, first, before spending money
5collected in later delivery years. Any interest earned shall
6be credited back to retail customers under the reconciliation
7proceeding provided for in this subsection (k), provided that
8the electric utility shall first be reimbursed from the
9interest for the administrative costs that it incurs to
10administer and manage the account. Any taxes due on the funds
11in the account, or interest earned on it, will be paid from the
12account or, if insufficient monies are available in the
13account, from the monies collected under the tariffed charges
14to recover the costs of procuring renewable energy resources.
15Monies deposited in the account shall be subject to the
16review, reconciliation, and true-up process described in this
17subsection (k) that is applicable to the funds collected and
18costs incurred for the procurement of renewable energy
19resources.
20 The electric utility shall be entitled to recover all of
21the costs identified in this subsection (k) through automatic
22adjustment clause tariffs applicable to all of the utility's
23retail customers that allow the electric utility to adjust its
24tariffed charges consistent with this subsection (k). The
25determination as to whether any excess funds were collected
26during a given delivery year for the purchase of renewable

HB5856- 315 -LRB103 40655 LNS 73376 b
1energy resources, and the crediting of any excess funds back
2to retail customers, shall not be made until after the close of
3the delivery year, which will ensure that the maximum amount
4of funds is available to implement the approved long-term
5renewable resources procurement plan during a given delivery
6year. The amount of excess funds eligible to be credited back
7to retail customers shall be reduced by an amount equal to the
8payment obligations required by any contracts entered into by
9an electric utility under contracts described in subsection
10(b) of Section 1-56 and subsection (c) of Section 1-75 of the
11Illinois Power Agency Act, even if such payments have not yet
12been made and regardless of the delivery year in which those
13payment obligations were incurred. Notwithstanding anything to
14the contrary, including in tariffs authorized by this
15subsection (k) in effect before the effective date of this
16amendatory Act of the 102nd General Assembly, all unspent
17funds as of May 31, 2021, excluding any funds credited to
18customers during any utility billing cycle that commences
19prior to the effective date of this amendatory Act of the 102nd
20General Assembly, shall remain in the utility account and
21shall on a first in, first out basis be used toward utility
22payment obligations under contracts described in subsection
23(b) of Section 1-56 and subsection (c) of Section 1-75 of the
24Illinois Power Agency Act. The electric utility's collections
25under such automatic adjustment clause tariffs to recover the
26costs of renewable energy resources, zero emission credits

HB5856- 316 -LRB103 40655 LNS 73376 b
1from zero emission facilities, and carbon mitigation credits
2from carbon-free energy resources shall be subject to separate
3annual review, reconciliation, and true-up against actual
4costs by the Commission under a procedure that shall be
5specified in the electric utility's automatic adjustment
6clause tariffs and that shall be approved by the Commission in
7connection with its approval of such tariffs. The procedure
8shall provide that any difference between the electric
9utility's collections for zero emission credits and carbon
10mitigation credits under the automatic adjustment charges for
11an annual period and the electric utility's actual costs of
12zero emission credits from zero emission facilities and carbon
13mitigation credits from carbon-free energy resources for that
14same annual period shall be refunded to or collected from, as
15applicable, the electric utility's retail customers in
16subsequent periods.
17 Nothing in this subsection (k) is intended to affect,
18limit, or change the right of the electric utility to recover
19the costs associated with the procurement of renewable energy
20resources for periods commencing before, on, or after June 1,
212017, as otherwise provided in the Illinois Power Agency Act.
22 The funding available under this subsection (k), if any,
23for the programs described under subsection (b) of Section
241-56 of the Illinois Power Agency Act shall not reduce the
25amount of funding for the programs described in subparagraph
26(O) of paragraph (1) of subsection (c) of Section 1-75 of the

HB5856- 317 -LRB103 40655 LNS 73376 b
1Illinois Power Agency Act. If funding is available under this
2subsection (k) for programs described under subsection (b) of
3Section 1-56 of the Illinois Power Agency Act, then the
4long-term renewable resources plan shall provide for the
5Agency to procure contracts in an amount that does not exceed
6the funding, and the contracts approved by the Commission
7shall be executed by the applicable utility or utilities.
8 (l) A utility that has terminated any contract executed
9under subsection (d-5) or (d-10) of Section 1-75 of the
10Illinois Power Agency Act shall be entitled to recover any
11remaining balance associated with the purchase of zero
12emission credits prior to such termination, and such utility
13shall also apply a credit to its retail customer bills in the
14event of any over-collection.
15 (m)(1) An electric utility that recovers its costs of
16procuring zero emission credits from zero emission facilities
17through a cents-per-kilowatthour charge under subsection (k)
18of this Section shall be subject to the requirements of this
19subsection (m). Notwithstanding anything to the contrary, such
20electric utility shall, beginning on April 30, 2018, and each
21April 30 thereafter until April 30, 2026, calculate whether
22any reduction must be applied to such cents-per-kilowatthour
23charge that is paid by retail customers of the electric
24utility that have opted out of subsections (a) through (j) of
25Section 8-103B of this Act under subsection (l) of Section
268-103B. Such charge shall be reduced for such customers for

HB5856- 318 -LRB103 40655 LNS 73376 b
1the next delivery year commencing on June 1 based on the amount
2necessary, if any, to limit the annual estimated average net
3increase for the prior calendar year due to the future energy
4investment costs to no more than 1.3% of 5.98 cents per
5kilowatt-hour, which is the average amount paid per
6kilowatthour for electric service during the year ending
7December 31, 2015 by Illinois industrial retail customers, as
8reported to the Edison Electric Institute.
9 The calculations required by this subsection (m) shall be
10made only once for each year, and no subsequent rate impact
11determinations shall be made.
12 (2) For purposes of this Section, "future energy
13investment costs" shall be calculated by subtracting the
14cents-per-kilowatthour charge identified in subparagraph (A)
15of this paragraph (2) from the sum of the
16cents-per-kilowatthour charges identified in subparagraph (B)
17of this paragraph (2):
18 (A) The cents-per-kilowatthour charge identified in
19 the electric utility's tariff placed into effect under
20 Section 8-103 of the Public Utilities Act that, on
21 December 1, 2016, was applicable to those retail customers
22 that have opted out of subsections (a) through (j) of
23 Section 8-103B of this Act under subsection (l) of Section
24 8-103B.
25 (B) The sum of the following cents-per-kilowatthour
26 charges applicable to those retail customers that have

HB5856- 319 -LRB103 40655 LNS 73376 b
1 opted out of subsections (a) through (j) of Section 8-103B
2 of this Act under subsection (l) of Section 8-103B,
3 provided that if one or more of the following charges has
4 been in effect and applied to such customers for more than
5 one calendar year, then each charge shall be equal to the
6 average of the charges applied over a period that
7 commences with the calendar year ending December 31, 2017
8 and ends with the most recently completed calendar year
9 prior to the calculation required by this subsection (m):
10 (i) the cents-per-kilowatthour charge to recover
11 the costs incurred by the utility under subsection
12 (d-5) of Section 1-75 of the Illinois Power Agency
13 Act, adjusted for any reductions required under this
14 subsection (m); and
15 (ii) the cents-per-kilowatthour charge to recover
16 the costs incurred by the utility under Section
17 16-107.6 of the Public Utilities Act.
18 If no charge was applied for a given calendar year
19 under item (i) or (ii) of this subparagraph (B), then the
20 value of the charge for that year shall be zero.
21 (3) If a reduction is required by the calculation
22performed under this subsection (m), then the amount of the
23reduction shall be multiplied by the number of years reflected
24in the averages calculated under subparagraph (B) of paragraph
25(2) of this subsection (m). Such reduction shall be applied to
26the cents-per-kilowatthour charge that is applicable to those

HB5856- 320 -LRB103 40655 LNS 73376 b
1retail customers that have opted out of subsections (a)
2through (j) of Section 8-103B of this Act under subsection (l)
3of Section 8-103B beginning with the next delivery year
4commencing after the date of the calculation required by this
5subsection (m).
6 (4) The electric utility shall file a notice with the
7Commission on May 1 of 2018 and each May 1 thereafter until May
81, 2026 containing the reduction, if any, which must be
9applied for the delivery year which begins in the year of the
10filing. The notice shall contain the calculations made
11pursuant to this Section. By October 1 of each year beginning
12in 2018, each electric utility shall notify the Commission if
13it appears, based on an estimate of the calculation required
14in this subsection (m), that a reduction will be required in
15the next year.
16(Source: P.A. 102-662, eff. 9-15-21.)
17 (220 ILCS 5/16-111.5)
18 Sec. 16-111.5. Provisions relating to procurement.
19 (a) An electric utility that on December 31, 2005 served
20at least 100,000 customers in Illinois shall procure power and
21energy for its eligible retail customers in accordance with
22the applicable provisions set forth in Section 1-75 of the
23Illinois Power Agency Act and this Section. Beginning with the
24delivery year commencing on June 1, 2024, an electric utility
25serving over 100,000 customers in Illinois shall also procure

HB5856- 321 -LRB103 40655 LNS 73376 b
1energy storage credits in accordance with the applicable
2provisions of Sections 1-75 and 1-93 of the Illinois Power
3Agency Act and this Section. Beginning with the delivery year
4commencing on June 1, 2017, such electric utility shall also
5procure zero emission credits from zero emission facilities in
6accordance with the applicable provisions set forth in Section
71-75 of the Illinois Power Agency Act, and, for years
8beginning on or after June 1, 2017, the utility shall procure
9renewable energy resources in accordance with the applicable
10provisions set forth in Section 1-75 of the Illinois Power
11Agency Act and this Section. Beginning with the delivery year
12commencing on June 1, 2022, an electric utility serving over
133,000,000 customers shall also procure carbon mitigation
14credits from carbon-free energy resources in accordance with
15the applicable provisions set forth in Section 1-75 of the
16Illinois Power Agency Act and this Section. A small
17multi-jurisdictional electric utility that on December 31,
182005 served less than 100,000 customers in Illinois may elect
19to procure power and energy for all or a portion of its
20eligible Illinois retail customers in accordance with the
21applicable provisions set forth in this Section and Section
221-75 of the Illinois Power Agency Act. This Section shall not
23apply to a small multi-jurisdictional utility until such time
24as a small multi-jurisdictional utility requests the Illinois
25Power Agency to prepare a procurement plan for its eligible
26retail customers. "Eligible retail customers" for the purposes

HB5856- 322 -LRB103 40655 LNS 73376 b
1of this Section means those retail customers that purchase
2power and energy from the electric utility under fixed-price
3bundled service tariffs, other than those retail customers
4whose service is declared or deemed competitive under Section
516-113 and those other customer groups specified in this
6Section, including self-generating customers, customers
7electing hourly pricing, or those customers who are otherwise
8ineligible for fixed-price bundled tariff service. For those
9customers that are excluded from the procurement plan's
10electric supply service requirements, and the utility shall
11procure any supply requirements, including capacity, ancillary
12services, and hourly priced energy, in the applicable markets
13as needed to serve those customers, provided that the utility
14may include in its procurement plan load requirements for the
15load that is associated with those retail customers whose
16service has been declared or deemed competitive pursuant to
17Section 16-113 of this Act to the extent that those customers
18are purchasing power and energy during one of the transition
19periods identified in subsection (b) of Section 16-113 of this
20Act.
21 (b) A procurement plan shall be prepared for each electric
22utility consistent with the applicable requirements of the
23Illinois Power Agency Act and this Section. For purposes of
24this Section, Illinois electric utilities that are affiliated
25by virtue of a common parent company are considered to be a
26single electric utility. Small multi-jurisdictional utilities

HB5856- 323 -LRB103 40655 LNS 73376 b
1may request a procurement plan for a portion of or all of its
2Illinois load. Each procurement plan shall analyze the
3projected balance of supply and demand for those retail
4customers to be included in the plan's electric supply service
5requirements over a 5-year period, with the first planning
6year beginning on June 1 of the year following the year in
7which the plan is filed. The plan shall specifically identify
8the wholesale products to be procured following plan approval,
9and shall follow all the requirements set forth in the Public
10Utilities Act and all applicable State and federal laws,
11statutes, rules, or regulations, as well as Commission orders.
12Nothing in this Section precludes consideration of contracts
13longer than 5 years and related forecast data. Unless
14specified otherwise in this Section, in the procurement plan
15or in the implementing tariff, any procurement occurring in
16accordance with this plan shall be competitively bid through a
17request for proposals process. Approval and implementation of
18the procurement plan shall be subject to review and approval
19by the Commission according to the provisions set forth in
20this Section. A procurement plan shall include each of the
21following components:
22 (1) Hourly load analysis. This analysis shall include:
23 (i) multi-year historical analysis of hourly
24 loads;
25 (ii) switching trends and competitive retail
26 market analysis;

HB5856- 324 -LRB103 40655 LNS 73376 b
1 (iii) known or projected changes to future loads;
2 and
3 (iv) growth forecasts by customer class; and .
4 (v) the impact of load reduction and peak load
5 reduction through programs authorized by Sections
6 16-107.9, 16-107.10, and 16-107.11.
7 (2) Analysis of the impact of any demand side and
8 renewable energy initiatives. This analysis shall include:
9 (i) the impact of demand response programs and
10 energy efficiency programs, both current and
11 projected; for small multi-jurisdictional utilities,
12 the impact of demand response and energy efficiency
13 programs approved pursuant to Section 8-408 of this
14 Act, both current and projected; and
15 (ii) supply side needs that are projected to be
16 offset by purchases of renewable energy resources, if
17 any.
18 (3) A plan for meeting the expected load requirements
19 that will not be met through preexisting contracts. This
20 plan shall include:
21 (i) definitions of the different Illinois retail
22 customer classes for which supply is being purchased;
23 (ii) the proposed mix of demand-response products
24 for which contracts will be executed during the next
25 year. For small multi-jurisdictional electric
26 utilities that on December 31, 2005 served fewer than

HB5856- 325 -LRB103 40655 LNS 73376 b
1 100,000 customers in Illinois, these shall be defined
2 as demand-response products offered in an energy
3 efficiency plan approved pursuant to Section 8-408 of
4 this Act. The cost-effective demand-response measures
5 shall be procured whenever the cost is lower than
6 procuring comparable capacity products, provided that
7 such products shall:
8 (A) be procured by a demand-response provider
9 from those retail customers included in the plan's
10 electric supply service requirements;
11 (B) at least satisfy the demand-response
12 requirements of the regional transmission
13 organization market in which the utility's service
14 territory is located, including, but not limited
15 to, any applicable capacity or dispatch
16 requirements;
17 (C) provide for customers' participation in
18 the stream of benefits produced by the
19 demand-response products;
20 (D) provide for reimbursement by the
21 demand-response provider of the utility for any
22 costs incurred as a result of the failure of the
23 supplier of such products to perform its
24 obligations thereunder; and
25 (E) meet the same credit requirements as apply
26 to suppliers of capacity, in the applicable

HB5856- 326 -LRB103 40655 LNS 73376 b
1 regional transmission organization market;
2 (iii) monthly forecasted system supply
3 requirements, including expected minimum, maximum, and
4 average values for the planning period;
5 (iv) the proposed mix and selection of standard
6 wholesale products for which contracts will be
7 executed during the next year, separately or in
8 combination, to meet that portion of its load
9 requirements not met through pre-existing contracts,
10 including but not limited to monthly 5 x 16 peak period
11 block energy, monthly off-peak wrap energy, monthly 7
12 x 24 energy, annual 5 x 16 energy, other standardized
13 energy or capacity products designed to provide
14 eligible retail customer benefits from commercially
15 deployed advanced technologies including but not
16 limited to high voltage direct current converter
17 stations, as such term is defined in Section 1-10 of
18 the Illinois Power Agency Act, whether or not such
19 product is currently available in wholesale markets,
20 annual off-peak wrap energy, annual 7 x 24 energy,
21 monthly capacity, annual capacity, peak load capacity
22 obligations, capacity purchase plan, and ancillary
23 services;
24 (v) proposed term structures for each wholesale
25 product type included in the proposed procurement plan
26 portfolio of products; and

HB5856- 327 -LRB103 40655 LNS 73376 b
1 (vi) an assessment of the price risk, load
2 uncertainty, and other factors that are associated
3 with the proposed procurement plan; this assessment,
4 to the extent possible, shall include an analysis of
5 the following factors: contract terms, time frames for
6 securing products or services, fuel costs, weather
7 patterns, transmission costs, market conditions, and
8 the governmental regulatory environment; the proposed
9 procurement plan shall also identify alternatives for
10 those portfolio measures that are identified as having
11 significant price risk and mitigation in the form of
12 additional retail customer and ratepayer price,
13 reliability, and environmental benefits from
14 standardized energy products delivered from
15 commercially deployed advanced technologies,
16 including, but not limited to, high voltage direct
17 current converter stations, as such term is defined in
18 Section 1-10 of the Illinois Power Agency Act, whether
19 or not such product is currently available in
20 wholesale markets.
21 (4) Proposed procedures for balancing loads. The
22 procurement plan shall include, for load requirements
23 included in the procurement plan, the process for (i)
24 hourly balancing of supply and demand and (ii) the
25 criteria for portfolio re-balancing in the event of
26 significant shifts in load.

HB5856- 328 -LRB103 40655 LNS 73376 b
1 (5) Long-Term Renewable Resources Procurement Plan.
2 The Agency shall prepare a long-term renewable resources
3 procurement plan for the procurement of renewable energy
4 credits under Sections 1-56 and 1-75 of the Illinois Power
5 Agency Act for delivery beginning in the 2017 delivery
6 year.
7 (i) The initial long-term renewable resources
8 procurement plan and all subsequent revisions shall be
9 subject to review and approval by the Commission. For
10 the purposes of this Section, "delivery year" has the
11 same meaning as in Section 1-10 of the Illinois Power
12 Agency Act. For purposes of this Section, "Agency"
13 shall mean the Illinois Power Agency.
14 (ii) The long-term renewable resources planning
15 process shall be conducted as follows:
16 (A) Electric utilities shall provide a range
17 of load forecasts to the Illinois Power Agency
18 within 45 days of the Agency's request for
19 forecasts, which request shall specify the length
20 and conditions for the forecasts including, but
21 not limited to, the quantity of distributed
22 generation expected to be interconnected for each
23 year.
24 (B) The Agency shall publish for comment the
25 initial long-term renewable resources procurement
26 plan no later than 120 days after the effective

HB5856- 329 -LRB103 40655 LNS 73376 b
1 date of this amendatory Act of the 99th General
2 Assembly and shall review, and may revise, the
3 plan at least every 2 years thereafter. To the
4 extent practicable, the Agency shall review and
5 propose any revisions to the long-term renewable
6 energy resources procurement plan in conjunction
7 with the Agency's other planning and approval
8 processes conducted under this Section. The
9 initial long-term renewable resources procurement
10 plan shall:
11 (aa) Identify the procurement programs and
12 competitive procurement events consistent with
13 the applicable requirements of the Illinois
14 Power Agency Act and shall be designed to
15 achieve the goals set forth in subsection (c)
16 of Section 1-75 of that Act.
17 (bb) Include a schedule for procurements
18 for renewable energy credits from
19 utility-scale wind projects, utility-scale
20 solar projects, and brownfield site
21 photovoltaic projects consistent with
22 subparagraph (G) of paragraph (1) of
23 subsection (c) of Section 1-75 of the Illinois
24 Power Agency Act.
25 (cc) Identify the process whereby the
26 Agency will submit to the Commission for

HB5856- 330 -LRB103 40655 LNS 73376 b
1 review and approval the proposed contracts to
2 implement the programs required by such plan.
3 Copies of the initial long-term renewable
4 resources procurement plan and all subsequent
5 revisions shall be posted and made publicly
6 available on the Agency's and Commission's
7 websites, and copies shall also be provided to
8 each affected electric utility. An affected
9 utility and other interested parties shall have 45
10 days following the date of posting to provide
11 comment to the Agency on the initial long-term
12 renewable resources procurement plan and all
13 subsequent revisions. All comments submitted to
14 the Agency shall be specific, supported by data or
15 other detailed analyses, and, if objecting to all
16 or a portion of the procurement plan, accompanied
17 by specific alternative wording or proposals. All
18 comments shall be posted on the Agency's and
19 Commission's websites. During this 45-day comment
20 period, the Agency shall hold at least one public
21 hearing within each utility's service area that is
22 subject to the requirements of this paragraph (5)
23 for the purpose of receiving public comment.
24 Within 21 days following the end of the 45-day
25 review period, the Agency may revise the long-term
26 renewable resources procurement plan based on the

HB5856- 331 -LRB103 40655 LNS 73376 b
1 comments received and shall file the plan with the
2 Commission for review and approval.
3 (C) Within 14 days after the filing of the
4 initial long-term renewable resources procurement
5 plan or any subsequent revisions, any person
6 objecting to the plan may file an objection with
7 the Commission. Within 21 days after the filing of
8 the plan, the Commission shall determine whether a
9 hearing is necessary. The Commission shall enter
10 its order confirming or modifying the initial
11 long-term renewable resources procurement plan or
12 any subsequent revisions within 120 days after the
13 filing of the plan by the Illinois Power Agency.
14 (D) The Commission shall approve the initial
15 long-term renewable resources procurement plan and
16 any subsequent revisions, including expressly the
17 forecast used in the plan and taking into account
18 that funding will be limited to the amount of
19 revenues actually collected by the utilities, if
20 the Commission determines that the plan will
21 reasonably and prudently accomplish the
22 requirements of Section 1-56 and subsection (c) of
23 Section 1-75 of the Illinois Power Agency Act. The
24 Commission shall also approve the process for the
25 submission, review, and approval of the proposed
26 contracts to procure renewable energy credits or

HB5856- 332 -LRB103 40655 LNS 73376 b
1 implement the programs authorized by the
2 Commission pursuant to a long-term renewable
3 resources procurement plan approved under this
4 Section.
5 In approving any long-term renewable resources
6 procurement plan after the effective date of this
7 amendatory Act of the 102nd General Assembly, the
8 Commission shall approve or modify the Agency's
9 proposal for minimum equity standards pursuant to
10 subsection (c-10) of Section 1-75 of the Illinois
11 Power Agency Act. The Commission shall consider
12 any analysis performed by the Agency in developing
13 its proposal, including past performance,
14 availability of equity eligible contractors, and
15 availability of equity eligible persons at the
16 time the long-term renewable resources procurement
17 plan is approved.
18 (iii) The Agency or third parties contracted by
19 the Agency shall implement all programs authorized by
20 the Commission in an approved long-term renewable
21 resources procurement plan without further review and
22 approval by the Commission. Third parties shall not
23 begin implementing any programs or receive any payment
24 under this Section until the Commission has approved
25 the contract or contracts under the process authorized
26 by the Commission in item (D) of subparagraph (ii) of

HB5856- 333 -LRB103 40655 LNS 73376 b
1 paragraph (5) of this subsection (b) and the third
2 party and the Agency or utility, as applicable, have
3 executed the contract. For those renewable energy
4 credits subject to procurement through a competitive
5 bid process under the plan or under the initial
6 forward procurements for wind and solar resources
7 described in subparagraph (G) of paragraph (1) of
8 subsection (c) of Section 1-75 of the Illinois Power
9 Agency Act, the Agency shall follow the procurement
10 process specified in the provisions relating to
11 electricity procurement in subsections (e) through (i)
12 of this Section.
13 (iv) An electric utility shall recover its costs
14 associated with the procurement of renewable energy
15 credits under this Section and pursuant to subsection
16 (c-5) of Section 1-75 of the Illinois Power Agency Act
17 through an automatic adjustment clause tariff under
18 subsection (k) or a tariff pursuant to subsection
19 (i-5), as applicable, of Section 16-108 of this Act. A
20 utility shall not be required to advance any payment
21 or pay any amounts under this Section that exceed the
22 actual amount of revenues collected by the utility
23 under paragraph (6) of subsection (c) of Section 1-75
24 of the Illinois Power Agency Act, subsection (c-5) of
25 Section 1-75 of the Illinois Power Agency Act, and
26 subsection (k) or subsection (i-5), as applicable, of

HB5856- 334 -LRB103 40655 LNS 73376 b
1 Section 16-108 of this Act, and contracts executed
2 under this Section shall expressly incorporate this
3 limitation.
4 (v) For the public interest, safety, and welfare,
5 the Agency and the Commission may adopt rules to carry
6 out the provisions of this Section on an emergency
7 basis immediately following the effective date of this
8 amendatory Act of the 99th General Assembly.
9 (vi) On or before July 1 of each year, the
10 Commission shall hold an informal hearing for the
11 purpose of receiving comments on the prior year's
12 procurement process and any recommendations for
13 change.
14 (6) Long-term energy storage resources procurement
15 plan. The Agency shall prepare an energy storage resources
16 procurement plan for the procurement of energy storage
17 credits in compliance with this Section and Section 1-93
18 of the Illinois Power Agency Act.
19 (i) The initial energy storage resources
20 procurement plan and all subsequent revisions shall be
21 subject to review and approval by the Commission. For
22 purposes of this Section, "delivery year" has the same
23 meaning as used in Section 1-10 of the Illinois Power
24 Agency Act. In this paragraph, "Agency" means the
25 Illinois Power Agency.
26 (ii) The energy storage resources planning process

HB5856- 335 -LRB103 40655 LNS 73376 b
1 shall be conducted as follows:
2 (A) The Agency shall publish for comment the
3 initial energy storage resources procurement plan
4 no later than 180 days after the effective date of
5 this amendatory Act of the 103rd General Assembly
6 and shall review and may revise the plan at least
7 every 2 years thereafter. To the extent
8 practicable, the Agency shall review and propose
9 any revisions to the energy storage resources
10 procurement plan in conjunction with the Agency's
11 other planning and approval processes conducted
12 under this Section. The initial energy storage
13 resources procurement plan shall:
14 (aa) include a schedule for procurements
15 for energy storage credits from qualified
16 energy storage systems consistent with Section
17 1-93 of the Illinois Power Agency Act,
18 including proposals for allocation between
19 indexed credits and tolling agreements;
20 (bb) identify the process whereby the
21 Agency will submit to the Commission for
22 review and approval the proposed contracts to
23 implement the programs required by the plan.
24 Copies of the initial energy storage resources
25 procurement plan and all subsequent revisions
26 shall be posted and made publicly available on

HB5856- 336 -LRB103 40655 LNS 73376 b
1 the Agency's and Commission's websites, and
2 copies shall also be provided to each affected
3 electric utility. An affected utility and
4 other interested parties shall have 45 days
5 following the date of posting to provide
6 comment to the Agency on the initial energy
7 storage resources procurement plan and all
8 subsequent revisions. All comments shall be
9 posted on the Agency's and Commission's
10 websites; and
11 (cc) upon solicitation from stakeholders,
12 consider additional procurement approaches
13 that would result in the electric utilities
14 contracting for energy storage to achieve the
15 requirements described in subsection (a); and
16 (B) The Commission shall approve the initial
17 energy storage resources procurement plan and any
18 subsequent revisions if the Commission determines
19 that the plan will reasonably and prudently
20 accomplish the requirements of Section 1-93 of the
21 Illinois Power Agency Act. The Commission shall
22 also approve the process for the submission,
23 review, and approval of the proposed contracts to
24 procure energy storage credits or implement the
25 programs authorized by the Commission pursuant to
26 a long-term energy storage resources procurement

HB5856- 337 -LRB103 40655 LNS 73376 b
1 plan approved under this Section.
2 In approving any long-term energy storage
3 procurement plan after the effective date of this
4 amendatory Act of the 103rd General Assembly, the
5 Commission shall approve or modify the Agency's
6 proposal for minimum equity standards under
7 subsection (c-10) of Section 1-75 of the Illinois
8 Power Agency Act. The Commission shall consider
9 any analysis performed by the Agency in developing
10 its proposal, including past performance,
11 availability of equity eligible contractors, and
12 availability of equity eligible persons at the
13 time the long-term renewable resources procurement
14 plan is approved.
15 (iii) The Agency or third parties contracted by
16 the Agency shall implement all programs authorized by
17 the Commission in an approved long-term energy storage
18 procurement plan without further review and approval
19 by the Commission. Third parties shall not begin
20 implementing any programs or receive any payment under
21 this Section until the Commission has approved the
22 long-term storage contract.
23 (iv) An electric utility shall recover its costs
24 associated with the procurement of energy storage
25 credits under this Section and pursuant to Section
26 1-93 of the Illinois Power Agency Act through an

HB5856- 338 -LRB103 40655 LNS 73376 b
1 automatic adjustment clause tariff under subsection
2 (k) or a tariff under subsection (i-5), as applicable,
3 of Section 16-108.
4 (b-5) An electric utility that as of January 1, 2019
5served more than 300,000 retail customers in this State shall
6purchase renewable energy credits from new renewable energy
7facilities constructed at or adjacent to the sites of
8coal-fueled electric generating facilities in this State in
9accordance with subsection (c-5) of Section 1-75 of the
10Illinois Power Agency Act. Except as expressly provided in
11this Section, the plans and procedures for such procurements
12shall not be included in the procurement plans provided for in
13this Section, but rather shall be conducted and implemented
14solely in accordance with subsection (c-5) of Section 1-75 of
15the Illinois Power Agency Act.
16 (c) The provisions of this subsection (c) shall not apply
17to procurements conducted pursuant to subsection (c-5) of
18Section 1-75 of the Illinois Power Agency Act. However, the
19Agency may retain a procurement administrator to assist the
20Agency in planning and carrying out the procurement events and
21implementing the other requirements specified in such
22subsection (c-5) of Section 1-75 of the Illinois Power Agency
23Act, with the costs incurred by the Agency for the procurement
24administrator to be recovered through fees charged to
25applicants for selection to sell and deliver renewable energy
26credits to electric utilities pursuant to subsection (c-5) of

HB5856- 339 -LRB103 40655 LNS 73376 b
1Section 1-75 of the Illinois Power Agency Act. The procurement
2process set forth in Section 1-75 of the Illinois Power Agency
3Act and subsection (e) of this Section shall be administered
4by a procurement administrator and monitored by a procurement
5monitor.
6 (1) The procurement administrator shall:
7 (i) design the final procurement process in
8 accordance with Section 1-75 of the Illinois Power
9 Agency Act and subsection (e) of this Section
10 following Commission approval of the procurement plan;
11 (ii) develop benchmarks in accordance with
12 subsection (e)(3) to be used to evaluate bids; these
13 benchmarks shall be submitted to the Commission for
14 review and approval on a confidential basis prior to
15 the procurement event;
16 (iii) serve as the interface between the electric
17 utility and suppliers;
18 (iv) manage the bidder pre-qualification and
19 registration process;
20 (v) obtain the electric utilities' agreement to
21 the final form of all supply contracts and credit
22 collateral agreements;
23 (vi) administer the request for proposals process;
24 (vii) have the discretion to negotiate to
25 determine whether bidders are willing to lower the
26 price of bids that meet the benchmarks approved by the

HB5856- 340 -LRB103 40655 LNS 73376 b
1 Commission; any post-bid negotiations with bidders
2 shall be limited to price only and shall be completed
3 within 24 hours after opening the sealed bids and
4 shall be conducted in a fair and unbiased manner; in
5 conducting the negotiations, there shall be no
6 disclosure of any information derived from proposals
7 submitted by competing bidders; if information is
8 disclosed to any bidder, it shall be provided to all
9 competing bidders;
10 (viii) maintain confidentiality of supplier and
11 bidding information in a manner consistent with all
12 applicable laws, rules, regulations, and tariffs;
13 (ix) submit a confidential report to the
14 Commission recommending acceptance or rejection of
15 bids;
16 (x) notify the utility of contract counterparties
17 and contract specifics; and
18 (xi) administer related contingency procurement
19 events.
20 (2) The procurement monitor, who shall be retained by
21 the Commission, shall:
22 (i) monitor interactions among the procurement
23 administrator, suppliers, and utility;
24 (ii) monitor and report to the Commission on the
25 progress of the procurement process;
26 (iii) provide an independent confidential report

HB5856- 341 -LRB103 40655 LNS 73376 b
1 to the Commission regarding the results of the
2 procurement event;
3 (iv) assess compliance with the procurement plans
4 approved by the Commission for each utility that on
5 December 31, 2005 provided electric service to at
6 least 100,000 customers in Illinois and for each small
7 multi-jurisdictional utility that on December 31, 2005
8 served less than 100,000 customers in Illinois;
9 (v) preserve the confidentiality of supplier and
10 bidding information in a manner consistent with all
11 applicable laws, rules, regulations, and tariffs;
12 (vi) provide expert advice to the Commission and
13 consult with the procurement administrator regarding
14 issues related to procurement process design, rules,
15 protocols, and policy-related matters; and
16 (vii) consult with the procurement administrator
17 regarding the development and use of benchmark
18 criteria, standard form contracts, credit policies,
19 and bid documents.
20 (d) Except as provided in subsection (j), the planning
21process shall be conducted as follows:
22 (1) Beginning in 2008, each Illinois utility procuring
23 power pursuant to this Section shall annually provide a
24 range of load forecasts to the Illinois Power Agency by
25 July 15 of each year, or such other date as may be required
26 by the Commission or Agency. The load forecasts shall

HB5856- 342 -LRB103 40655 LNS 73376 b
1 cover the 5-year procurement planning period for the next
2 procurement plan and shall include hourly data
3 representing a high-load, low-load, and expected-load
4 scenario for the load of those retail customers included
5 in the plan's electric supply service requirements. The
6 utility shall provide supporting data and assumptions for
7 each of the scenarios.
8 (2) Beginning in 2008, the Illinois Power Agency shall
9 prepare a procurement plan by August 15th of each year, or
10 such other date as may be required by the Commission. The
11 procurement plan shall identify the portfolio of
12 demand-response and power and energy products to be
13 procured. Cost-effective demand-response measures shall be
14 procured as set forth in item (iii) of subsection (b) of
15 this Section. Copies of the procurement plan shall be
16 posted and made publicly available on the Agency's and
17 Commission's websites, and copies shall also be provided
18 to each affected electric utility. An affected utility
19 shall have 30 days following the date of posting to
20 provide comment to the Agency on the procurement plan.
21 Other interested entities also may comment on the
22 procurement plan. All comments submitted to the Agency
23 shall be specific, supported by data or other detailed
24 analyses, and, if objecting to all or a portion of the
25 procurement plan, accompanied by specific alternative
26 wording or proposals. All comments shall be posted on the

HB5856- 343 -LRB103 40655 LNS 73376 b
1 Agency's and Commission's websites. During this 30-day
2 comment period, the Agency shall hold at least one public
3 hearing within each utility's service area for the purpose
4 of receiving public comment on the procurement plan.
5 Within 14 days following the end of the 30-day review
6 period, the Agency shall revise the procurement plan as
7 necessary based on the comments received and file the
8 procurement plan with the Commission and post the
9 procurement plan on the websites.
10 (3) Within 5 days after the filing of the procurement
11 plan, any person objecting to the procurement plan shall
12 file an objection with the Commission. Within 10 days
13 after the filing, the Commission shall determine whether a
14 hearing is necessary. The Commission shall enter its order
15 confirming or modifying the procurement plan within 90
16 days after the filing of the procurement plan by the
17 Illinois Power Agency.
18 (4) The Commission shall approve the procurement plan,
19 including expressly the forecast used in the procurement
20 plan, if the Commission determines that it will ensure
21 adequate, reliable, affordable, efficient, and
22 environmentally sustainable electric service at the lowest
23 total cost over time, taking into account any benefits of
24 price stability.
25 (4.5) The Commission shall review the Agency's
26 recommendations for the selection of applicants to enter

HB5856- 344 -LRB103 40655 LNS 73376 b
1 into long-term contracts for the sale and delivery of
2 renewable energy credits from new renewable energy
3 facilities to be constructed at or adjacent to the sites
4 of coal-fueled electric generating facilities in this
5 State in accordance with the provisions of subsection
6 (c-5) of Section 1-75 of the Illinois Power Agency Act,
7 and shall approve the Agency's recommendations if the
8 Commission determines that the applicants recommended by
9 the Agency for selection, the proposed new renewable
10 energy facilities to be constructed, the amounts of
11 renewable energy credits to be delivered pursuant to the
12 contracts, and the other terms of the contracts, are
13 consistent with the requirements of subsection (c-5) of
14 Section 1-75 of the Illinois Power Agency Act.
15 (e) The procurement process shall include each of the
16following components:
17 (1) Solicitation, pre-qualification, and registration
18 of bidders. The procurement administrator shall
19 disseminate information to potential bidders to promote a
20 procurement event, notify potential bidders that the
21 procurement administrator may enter into a post-bid price
22 negotiation with bidders that meet the applicable
23 benchmarks, provide supply requirements, and otherwise
24 explain the competitive procurement process. In addition
25 to such other publication as the procurement administrator
26 determines is appropriate, this information shall be

HB5856- 345 -LRB103 40655 LNS 73376 b
1 posted on the Illinois Power Agency's and the Commission's
2 websites. The procurement administrator shall also
3 administer the prequalification process, including
4 evaluation of credit worthiness, compliance with
5 procurement rules, and agreement to the standard form
6 contract developed pursuant to paragraph (2) of this
7 subsection (e). The procurement administrator shall then
8 identify and register bidders to participate in the
9 procurement event.
10 (2) Standard contract forms and credit terms and
11 instruments. The procurement administrator, in
12 consultation with the utilities, the Commission, and other
13 interested parties and subject to Commission oversight,
14 shall develop and provide standard contract forms for the
15 supplier contracts that meet generally accepted industry
16 practices. Standard credit terms and instruments that meet
17 generally accepted industry practices shall be similarly
18 developed. The procurement administrator shall make
19 available to the Commission all written comments it
20 receives on the contract forms, credit terms, or
21 instruments. If the procurement administrator cannot reach
22 agreement with the applicable electric utility as to the
23 contract terms and conditions, the procurement
24 administrator must notify the Commission of any disputed
25 terms and the Commission shall resolve the dispute. Except
26 as provided under item (vi) of subparagraph (G) of

HB5856- 346 -LRB103 40655 LNS 73376 b
1 paragraph (1) of subsection (c) of Section 1-75 of the
2 Illinois Power Agency Act, the The terms of the contracts
3 shall not be subject to negotiation by winning bidders,
4 and the bidders must agree to the terms of the contract in
5 advance so that winning bids are selected solely on the
6 basis of price.
7 (3) Establishment of a market-based price benchmark.
8 As part of the development of the procurement process, the
9 procurement administrator, in consultation with the
10 Commission staff, Agency staff, and the procurement
11 monitor, shall establish benchmarks for evaluating the
12 final prices in the contracts for each of the products
13 that will be procured through the procurement process. The
14 benchmarks shall be based on price data for similar
15 products for the same delivery period and same delivery
16 hub, or other delivery hubs after adjusting for that
17 difference. The price benchmarks may also be adjusted to
18 take into account differences between the information
19 reflected in the underlying data sources and the specific
20 products and procurement process being used to procure
21 power for the Illinois utilities. The benchmarks shall be
22 confidential but shall be provided to, and will be subject
23 to Commission review and approval, prior to a procurement
24 event.
25 (4) Request for proposals competitive procurement
26 process. The procurement administrator shall design and

HB5856- 347 -LRB103 40655 LNS 73376 b
1 issue a request for proposals to supply electricity in
2 accordance with each utility's procurement plan, as
3 approved by the Commission. The request for proposals
4 shall set forth a procedure for sealed, binding commitment
5 bidding with pay-as-bid settlement, and provision for
6 selection of bids on the basis of price.
7 (5) A plan for implementing contingencies in the event
8 of supplier default or failure of the procurement process
9 to fully meet the expected load requirement due to
10 insufficient supplier participation, Commission rejection
11 of results, or any other cause.
12 (i) Event of supplier default: In the event of
13 supplier default, the utility shall review the
14 contract of the defaulting supplier to determine if
15 the amount of supply is 200 megawatts or greater, and
16 if there are more than 60 days remaining of the
17 contract term. If both of these conditions are met,
18 and the default results in termination of the
19 contract, the utility shall immediately notify the
20 Illinois Power Agency that a request for proposals
21 must be issued to procure replacement power, and the
22 procurement administrator shall run an additional
23 procurement event. If the contracted supply of the
24 defaulting supplier is less than 200 megawatts or
25 there are less than 60 days remaining of the contract
26 term, the utility shall procure power and energy from

HB5856- 348 -LRB103 40655 LNS 73376 b
1 the applicable regional transmission organization
2 market, including ancillary services, capacity, and
3 day-ahead or real time energy, or both, for the
4 duration of the contract term to replace the
5 contracted supply; provided, however, that if a needed
6 product is not available through the regional
7 transmission organization market it shall be purchased
8 from the wholesale market.
9 (ii) Failure of the procurement process to fully
10 meet the expected load requirement: If the procurement
11 process fails to fully meet the expected load
12 requirement due to insufficient supplier participation
13 or due to a Commission rejection of the procurement
14 results, the procurement administrator, the
15 procurement monitor, and the Commission staff shall
16 meet within 10 days to analyze potential causes of low
17 supplier interest or causes for the Commission
18 decision. If changes are identified that would likely
19 result in increased supplier participation, or that
20 would address concerns causing the Commission to
21 reject the results of the prior procurement event, the
22 procurement administrator may implement those changes
23 and rerun the request for proposals process according
24 to a schedule determined by those parties and
25 consistent with Section 1-75 of the Illinois Power
26 Agency Act and this subsection. In any event, a new

HB5856- 349 -LRB103 40655 LNS 73376 b
1 request for proposals process shall be implemented by
2 the procurement administrator within 90 days after the
3 determination that the procurement process has failed
4 to fully meet the expected load requirement.
5 (iii) In all cases where there is insufficient
6 supply provided under contracts awarded through the
7 procurement process to fully meet the electric
8 utility's load requirement, the utility shall meet the
9 load requirement by procuring power and energy from
10 the applicable regional transmission organization
11 market, including ancillary services, capacity, and
12 day-ahead or real time energy, or both; provided,
13 however, that if a needed product is not available
14 through the regional transmission organization market
15 it shall be purchased from the wholesale market.
16 (6) The procurement processes described in this
17 subsection and in subsection (c-5) of Section 1-75 of the
18 Illinois Power Agency Act are exempt from the requirements
19 of the Illinois Procurement Code, pursuant to Section
20 20-10 of that Code.
21 (f) Within 2 business days after opening the sealed bids,
22the procurement administrator shall submit a confidential
23report to the Commission. The report shall contain the results
24of the bidding for each of the products along with the
25procurement administrator's recommendation for the acceptance
26and rejection of bids based on the price benchmark criteria

HB5856- 350 -LRB103 40655 LNS 73376 b
1and other factors observed in the process. The procurement
2monitor also shall submit a confidential report to the
3Commission within 2 business days after opening the sealed
4bids. The report shall contain the procurement monitor's
5assessment of bidder behavior in the process as well as an
6assessment of the procurement administrator's compliance with
7the procurement process and rules. The Commission shall review
8the confidential reports submitted by the procurement
9administrator and procurement monitor, and shall accept or
10reject the recommendations of the procurement administrator
11within 2 business days after receipt of the reports.
12 (g) Within 3 business days after the Commission decision
13approving the results of a procurement event, the utility
14shall enter into binding contractual arrangements with the
15winning suppliers using the standard form contracts; except
16that the utility shall not be required either directly or
17indirectly to execute the contracts if a tariff that is
18consistent with subsection (l) of this Section has not been
19approved and placed into effect for that utility.
20 (h) For the procurement of standard wholesale products,
21the names of the successful bidders and the load weighted
22average of the winning bid prices for each contract type and
23for each contract term shall be made available to the public at
24the time of Commission approval of a procurement event. For
25procurements conducted to meet the requirements of subsection
26(b) of Section 1-56 or subsection (c) of Section 1-75 of the

HB5856- 351 -LRB103 40655 LNS 73376 b
1Illinois Power Agency Act governed by the provisions of this
2Section, the address and nameplate capacity of the new
3renewable energy generating facility proposed by a winning
4bidder shall also be made available to the public at the time
5of Commission approval of a procurement event, along with the
6business address and contact information for any winning
7bidder. An estimate or approximation of the nameplate capacity
8of the new renewable energy generating facility may be
9disclosed if necessary to protect the confidentiality of
10individual bid prices.
11 The Commission, the procurement monitor, the procurement
12administrator, the Illinois Power Agency, and all participants
13in the procurement process shall maintain the confidentiality
14of all other supplier and bidding information in a manner
15consistent with all applicable laws, rules, regulations, and
16tariffs. Confidential information, including the confidential
17reports submitted by the procurement administrator and
18procurement monitor pursuant to subsection (f) of this
19Section, shall not be made publicly available and shall not be
20discoverable by any party in any proceeding, absent a
21compelling demonstration of need, nor shall those reports be
22admissible in any proceeding other than one for law
23enforcement purposes.
24 (h-5) For procurements conducted to meet the requirements
25of subsection (b) of Section 1-56 or subsection (c) of Section
261-75 of the Illinois Power Agency Act, the Illinois Power

HB5856- 352 -LRB103 40655 LNS 73376 b
1Agency shall release aggregated information related to
2participation levels across product types and the basis of
3rejection for non-accepted bids if the Commission, the
4procurement monitor, the procurement administrator, and the
5Illinois Power Agency determine that the release of this
6information would not result in the disclosure of confidential
7bid information or negatively impact the competitiveness of
8future renewable energy credit procurements.
9 (i) Within 2 business days after a Commission decision
10approving the results of a procurement event or such other
11date as may be required by the Commission from time to time,
12the utility shall file for informational purposes with the
13Commission its actual or estimated retail supply charges, as
14applicable, by customer supply group reflecting the costs
15associated with the procurement and computed in accordance
16with the tariffs filed pursuant to subsection (l) of this
17Section and approved by the Commission.
18 (j) Within 60 days following August 28, 2007 (the
19effective date of Public Act 95-481), each electric utility
20that on December 31, 2005 provided electric service to at
21least 100,000 customers in Illinois shall prepare and file
22with the Commission an initial procurement plan, which shall
23conform in all material respects to the requirements of the
24procurement plan set forth in subsection (b); provided,
25however, that the Illinois Power Agency Act shall not apply to
26the initial procurement plan prepared pursuant to this

HB5856- 353 -LRB103 40655 LNS 73376 b
1subsection. The initial procurement plan shall identify the
2portfolio of power and energy products to be procured and
3delivered for the period June 2008 through May 2009, and shall
4identify the proposed procurement administrator, who shall
5have the same experience and expertise as is required of a
6procurement administrator hired pursuant to Section 1-75 of
7the Illinois Power Agency Act. Copies of the procurement plan
8shall be posted and made publicly available on the
9Commission's website. The initial procurement plan may include
10contracts for renewable resources that extend beyond May 2009.
11 (i) Within 14 days following filing of the initial
12 procurement plan, any person may file a detailed objection
13 with the Commission contesting the procurement plan
14 submitted by the electric utility. All objections to the
15 electric utility's plan shall be specific, supported by
16 data or other detailed analyses. The electric utility may
17 file a response to any objections to its procurement plan
18 within 7 days after the date objections are due to be
19 filed. Within 7 days after the date the utility's response
20 is due, the Commission shall determine whether a hearing
21 is necessary. If it determines that a hearing is
22 necessary, it shall require the hearing to be completed
23 and issue an order on the procurement plan within 60 days
24 after the filing of the procurement plan by the electric
25 utility.
26 (ii) The order shall approve or modify the procurement

HB5856- 354 -LRB103 40655 LNS 73376 b
1 plan, approve an independent procurement administrator,
2 and approve or modify the electric utility's tariffs that
3 are proposed with the initial procurement plan. The
4 Commission shall approve the procurement plan if the
5 Commission determines that it will ensure adequate,
6 reliable, affordable, efficient, and environmentally
7 sustainable electric service at the lowest total cost over
8 time, taking into account any benefits of price stability.
9 (k) (Blank).
10 (k-5) (Blank).
11 (l) An electric utility shall recover its costs incurred
12under this Section and subsection (c-5) of Section 1-75 of the
13Illinois Power Agency Act, including, but not limited to, the
14costs of procuring power and energy demand-response resources
15under this Section and its costs for purchasing renewable
16energy credits pursuant to subsection (c-5) of Section 1-75 of
17the Illinois Power Agency Act. The utility shall file with the
18initial procurement plan its proposed tariffs through which
19its costs of procuring power that are incurred pursuant to a
20Commission-approved procurement plan and those other costs
21identified in this subsection (l), will be recovered. The
22tariffs shall include a formula rate or charge designed to
23pass through both the costs incurred by the utility in
24procuring a supply of electric power and energy for the
25applicable customer classes with no mark-up or return on the
26price paid by the utility for that supply, plus any just and

HB5856- 355 -LRB103 40655 LNS 73376 b
1reasonable costs that the utility incurs in arranging and
2providing for the supply of electric power and energy. The
3formula rate or charge shall also contain provisions that
4ensure that its application does not result in over or under
5recovery due to changes in customer usage and demand patterns,
6and that provide for the correction, on at least an annual
7basis, of any accounting errors that may occur. A utility
8shall recover through the tariff all reasonable costs incurred
9to implement or comply with any procurement plan that is
10developed and put into effect pursuant to Section 1-75 of the
11Illinois Power Agency Act and this Section, and for the
12procurement of renewable energy credits pursuant to subsection
13(c-5) of Section 1-75 of the Illinois Power Agency Act,
14including any fees assessed by the Illinois Power Agency,
15costs associated with load balancing, and contingency plan
16costs. The electric utility shall also recover its full costs
17of procuring electric supply for which it contracted before
18the effective date of this Section in conjunction with the
19provision of full requirements service under fixed-price
20bundled service tariffs subsequent to December 31, 2006. All
21such costs shall be deemed to have been prudently incurred.
22The pass-through tariffs that are filed and approved pursuant
23to this Section shall not be subject to review under, or in any
24way limited by, Section 16-111(i) of this Act. All of the costs
25incurred by the electric utility associated with the purchase
26of zero emission credits in accordance with subsection (d-5)

HB5856- 356 -LRB103 40655 LNS 73376 b
1of Section 1-75 of the Illinois Power Agency Act, all costs
2incurred by the electric utility associated with the purchase
3of carbon mitigation credits in accordance with subsection
4(d-10) of Section 1-75 of the Illinois Power Agency Act, and,
5beginning June 1, 2017, all of the costs incurred by the
6electric utility associated with the purchase of renewable
7energy resources in accordance with Sections 1-56 and 1-75 of
8the Illinois Power Agency Act, and all of the costs incurred by
9the electric utility in purchasing renewable energy credits in
10accordance with subsection (c-5) of Section 1-75 of the
11Illinois Power Agency Act, and all costs incurred by the
12electric utility in purchasing energy storage credits in
13accordance with Section 1-93 of the Illinois Power Agency Act
14shall be recovered through the electric utility's tariffed
15charges applicable to all of its retail customers, as
16specified in subsection (k) or subsection (i-5), as
17applicable, of Section 16-108 of this Act, and shall not be
18recovered through the electric utility's tariffed charges for
19electric power and energy supply to its eligible retail
20customers.
21 (m) The Commission has the authority to adopt rules to
22carry out the provisions of this Section. For the public
23interest, safety, and welfare, the Commission also has
24authority to adopt rules to carry out the provisions of this
25Section on an emergency basis immediately following August 28,
262007 (the effective date of Public Act 95-481).

HB5856- 357 -LRB103 40655 LNS 73376 b
1 (n) Notwithstanding any other provision of this Act, any
2affiliated electric utilities that submit a single procurement
3plan covering their combined needs may procure for those
4combined needs in conjunction with that plan, and may enter
5jointly into power supply contracts, purchases, and other
6procurement arrangements, and allocate capacity and energy and
7cost responsibility therefor among themselves in proportion to
8their requirements.
9 (o) On or before June 1 of each year, the Commission shall
10hold an informal hearing for the purpose of receiving comments
11on the prior year's procurement process and any
12recommendations for change.
13 (p) An electric utility subject to this Section may
14propose to invest, lease, own, or operate an electric
15generation facility as part of its procurement plan, provided
16the utility demonstrates that such facility is the least-cost
17option to provide electric service to those retail customers
18included in the plan's electric supply service requirements.
19If the facility is shown to be the least-cost option and is
20included in a procurement plan prepared in accordance with
21Section 1-75 of the Illinois Power Agency Act and this
22Section, then the electric utility shall make a filing
23pursuant to Section 8-406 of this Act, and may request of the
24Commission any statutory relief required thereunder. If the
25Commission grants all of the necessary approvals for the
26proposed facility, such supply shall thereafter be considered

HB5856- 358 -LRB103 40655 LNS 73376 b
1as a pre-existing contract under subsection (b) of this
2Section. The Commission shall in any order approving a
3proposal under this subsection specify how the utility will
4recover the prudently incurred costs of investing in, leasing,
5owning, or operating such generation facility through just and
6reasonable rates charged to those retail customers included in
7the plan's electric supply service requirements. Cost recovery
8for facilities included in the utility's procurement plan
9pursuant to this subsection shall not be subject to review
10under or in any way limited by the provisions of Section
1116-111(i) of this Act. Nothing in this Section is intended to
12prohibit a utility from filing for a fuel adjustment clause as
13is otherwise permitted under Section 9-220 of this Act.
14 (q) If the Illinois Power Agency filed with the
15Commission, under Section 16-111.5 of this Act, its proposed
16procurement plan for the period commencing June 1, 2017, and
17the Commission has not yet entered its final order approving
18the plan on or before the effective date of this amendatory Act
19of the 99th General Assembly, then the Illinois Power Agency
20shall file a notice of withdrawal with the Commission, after
21the effective date of this amendatory Act of the 99th General
22Assembly, to withdraw the proposed procurement of renewable
23energy resources to be approved under the plan, other than the
24procurement of renewable energy credits from distributed
25renewable energy generation devices using funds previously
26collected from electric utilities' retail customers that take

HB5856- 359 -LRB103 40655 LNS 73376 b
1service pursuant to electric utilities' hourly pricing tariff
2or tariffs and, for an electric utility that serves less than
3100,000 retail customers in the State, other than the
4procurement of renewable energy credits from distributed
5renewable energy generation devices. Upon receipt of the
6notice, the Commission shall enter an order that approves the
7withdrawal of the proposed procurement of renewable energy
8resources from the plan. The initially proposed procurement of
9renewable energy resources shall not be approved or be the
10subject of any further hearing, investigation, proceeding, or
11order of any kind.
12 This amendatory Act of the 99th General Assembly preempts
13and supersedes any order entered by the Commission that
14approved the Illinois Power Agency's procurement plan for the
15period commencing June 1, 2017, to the extent it is
16inconsistent with the provisions of this amendatory Act of the
1799th General Assembly. To the extent any previously entered
18order approved the procurement of renewable energy resources,
19the portion of that order approving the procurement shall be
20void, other than the procurement of renewable energy credits
21from distributed renewable energy generation devices using
22funds previously collected from electric utilities' retail
23customers that take service under electric utilities' hourly
24pricing tariff or tariffs and, for an electric utility that
25serves less than 100,000 retail customers in the State, other
26than the procurement of renewable energy credits for

HB5856- 360 -LRB103 40655 LNS 73376 b
1distributed renewable energy generation devices.
2(Source: P.A. 102-662, eff. 9-15-21.)
3 (220 ILCS 5/Art. XXIII heading new)
4
ARTICLE XXIII. OFFICE OF INTERCONNECTION AND RENEWABLE
5
DEVELOPMENT
6 (220 ILCS 5/23-101 new)
7 Sec. 23-101. Findings and intent. The General Assembly
8finds and declares:
9 (1) The ability of the Commission and the Illinois
10 Power Agency to ensure long-term benefits from community
11 renewable generation projects and distributed renewable
12 energy generation devices is limited. For Illinois
13 consumers to continue to receive the substantial financial
14 and environmental benefits of deployment of distributed
15 renewable generation resources, including devices paired
16 with energy storage, the Commission must gather additional
17 data and proactively identify barriers.
18 (2) To date, as a result of the Future Energy Jobs Act
19 and the Climate and Equitable Jobs Act, tens of thousands
20 of Illinois retail customers of all sizes have experienced
21 the benefits of new renewable generation.
22 (3) However, as renewable generation deployment
23 increases, but remains short of the goals set by the
24 Climate and Equitable Jobs Act, it is critical that the

HB5856- 361 -LRB103 40655 LNS 73376 b
1 Commission proactively identify and address barriers to
2 achieving those goals.
3 (4) The Commission should promote the efficient
4 deployment of distributed renewable generation resources.
5 (220 ILCS 5/23-105 new)
6 Sec. 23-105. Definitions. In this Article:
7 "Director" means the Director of the Office of
8Interconnection and Renewable Development.
9 "Distributed renewable energy resources" means a community
10renewable generation device or a distributed renewable energy
11generation device as those terms are defined in Section 1-10
12of the Illinois Power Agency Act. "Distributed renewable
13energy resource" includes storage paired with a community
14renewable generation device or a distributed renewable energy
15generation device.
16 "Energy storage system" has the meaning given to that term
17in Section 1-10 of the Illinois Power Agency Act.
18 "Office" means the Office of Interconnection and Renewable
19Development.
20 "Utility-scale solar project" and "utility-scale wind
21project" have the meanings given to those terms in Section
221-10 of the Illinois Power Agency Act.
23 (220 ILCS 5/23-110 new)
24 Sec. 23-110. Office of Interconnection and Renewable

HB5856- 362 -LRB103 40655 LNS 73376 b
1Development.
2 (a) Within 90 days after the effective date of this
3amendatory Act of the 103rd General Assembly, subject to
4appropriation, the Commission shall establish an Office of
5Interconnection and Renewable Development and employ a
6Director of Interconnection and Renewable Development to
7oversee the Office. The Director shall have authority to
8employ or otherwise retain at least 3 professionals dedicated
9to the task of actively seeking out ways to identify barriers
10to deployment of distributed renewable energy resources.
11 (b) The Office shall actively seek input from all
12interested parties and shall develop a thorough understanding
13and critical analyses of the tools and techniques used to
14promote development and remove barriers to development of the
15projects and devices. The Office shall take these steps for
16interconnections involving distributed renewable energy
17resources, energy storage systems, utility-scale wind
18projects, and utility-scale solar projects, including
19interconnections to a distribution system or a transmission
20system.
21 (c) The Office shall monitor interconnection between
22electric utilities and applicants for interconnection and
23interconnection customers. The Office shall request, and
24electric utilities shall promptly provide, information and
25records related to pending, successful, and terminated
26interconnections. The Office shall include at least one

HB5856- 363 -LRB103 40655 LNS 73376 b
1employee with a background in engineering of distribution
2interconnections. The Office shall take these steps for
3interconnections involving distributed renewable energy
4resources, energy storage systems, utility-scale wind
5projects, and utility-scale solar projects, including
6interconnections to a distribution system or a transmission
7system.
8 (d) The Office shall employ an Ombudsperson who, in
9addition to the roles described in paragraph (2) of subsection
10(h-5) of Section 16-107.5, is responsible for oversight of all
11utility's compliance with the rules adopted under subsection
12(h) of Section 16-107.5 and any utility interconnection
13policies or procedures. The Ombudsperson may request, and each
14electric utility shall timely provide, records and information
15as the Ombudsperson may request from time to time to carry out
16his or her duties under this subsection or subsection (m) of
17Section 1-93 of the Illinois Power Agency Act. At any time, the
18Ombudsperson may issue a report to the Commission detailing
19any suspected violations of this Act or rules adopted by the
20Commission under this Act concerning interconnection processes
21or a particular interconnection.
22 (220 ILCS 5/23-115 new)
23 Sec. 23-115. Annual report. The Office shall collect and
24annually report to the Commission information about net
25metering under Section 16-107.5. The Office shall quantify the

HB5856- 364 -LRB103 40655 LNS 73376 b
1totality of retail customer benefits from net metering,
2including an assessment of customer value from net metering
3and net metering offered under subsection (l) of Section
416-107.5. The Office shall include information about
5distributed renewable energy resources outside of Illinois
6Power Agency programs and procurements identified in Sections
71-56 and 1-75 of the Illinois Power Agency Act.
8 (220 ILCS 5/23-120 new)
9 Sec. 23-120. Interconnection Working Group.
10 (a) The Ombudsperson shall provide to the Commission with
11a biennial update on consensus and non-consensus items
12addressed in the Interconnection Working Group. The
13Ombudsperson shall provide recommendation for Commission
14actions and the proposed timing of the actions based on the
15findings of the Interconnection Working Group.
16 (b) In collaboration with the Ethics Officer of the
17Commission, the Office shall develop policies and procedures
18to facilitate employees of the Office in leading the
19Interconnection Working Group described in subsection (h-5) of
20Section 16-107.5 without interference with docketed
21proceedings. The policies and procedures developed under this
22subsection shall be designed to allow the Interconnection
23Working Group to work without interruption.
24 Section 99. Effective date. This Act takes effect upon
25becoming law.

HB5856- 365 -LRB103 40655 LNS 73376 b
1 INDEX
2 Statutes amended in order of appearance