Bill Text: IL HB3758 | 2025-2026 | 104th General Assembly | Introduced

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Bill Title: Amends the Illinois Power Agency Act. Adds and modifies definitions of terms. Authorizes the Illinois Power Agency to conduct competitive solicitations to procure contracted energy storage credits sufficient to achieve certain energy storage standards; to request, review, and accept proposals; to execute contracts; and to 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.

Sponsorship: Partisan Bill (Democrat 2)

Status: (Introduced - Dead) 2025-05-09 - Added Co-Sponsor Rep. Kelly M. Cassidy [HB3758 Detail]

Download: Illinois-2025-HB3758-Introduced.html

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104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3758 Introduced , by Rep. Marcus C. Evans, Jr. SYNOPSIS AS INTRODUCED:
See Index
Amends the Illinois Power Agency Act. Adds and modifies definitions of terms. Authorizes the Illinois Power Agency to conduct competitive solicitations to procure contracted energy storage credits sufficient to achieve certain energy storage standards; to request, review, and accept proposals; to execute contracts; and to 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.
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A BILL FOR
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AN ACT concerning regulation.
Be it enacted by the People of the State of Illinois,
represented in the General Assembly:
Section 5. The Illinois Power Agency Act is amended by
changing Sections 1-5, 1-10, 1-20, and 1-75 and by adding
Sections 1-93 and 1-94 as follows:
(20 ILCS 3855/1-5)
Sec. 1-5. Legislative declarations and findings. The
General Assembly finds and declares:
(1) The health, welfare, and prosperity of all
Illinois residents require the provision of adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability.
(1.5) To provide the highest quality of life for the
residents of Illinois and to provide for a clean and
healthy environment, it is the policy of this State to
rapidly transition to 100% clean energy by 2050.
(2) (Blank).
(3) (Blank).
(4) It is necessary to improve the process of
procuring electricity to serve Illinois residents, to
promote investment in energy efficiency and

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

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

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

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

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

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

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

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

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

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

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

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together with such other expenses as may be necessary or
incidental to the financing, insuring, acquisition, and
construction of a specific project and starting up,
commissioning, and placing that project in operation.
"Delivery services" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Delivery year" means the consecutive 12-month period
beginning June 1 of a given year and ending May 31 of the
following year.
"Department" means the Department of Commerce and Economic
Opportunity.
"Director" means the Director of the Illinois Power
Agency.
"Demand-response" means measures that decrease peak
electricity demand or shift demand from peak to off-peak
periods.
"Distributed renewable energy generation device" means a
device that is:
(1) powered by wind, solar thermal energy,
photovoltaic cells or panels, biodiesel, crops and
untreated and unadulterated organic waste biomass, tree
waste, and hydropower that does not involve new
construction of dams, waste heat to power systems, or
qualified combined heat and power systems;
(2) interconnected at the distribution system level of
either an electric utility as defined in this Section, a

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municipal utility as defined in this Section that owns or
operates electric distribution facilities, or a rural
electric cooperative as defined in Section 3-119 of the
Public Utilities Act;
(3) located on the customer side of the customer's
electric meter and is primarily used to offset that
customer's electricity load; and
(4) (blank).
"Energy efficiency" means measures that reduce the amount
of electricity or natural gas consumed in order to achieve a
given end use. "Energy efficiency" includes voltage
optimization measures that optimize the voltage at points on
the electric distribution voltage system and thereby reduce
electricity consumption by electric customers' end use
devices. "Energy efficiency" also includes measures that
reduce the total Btus of electricity, natural gas, and other
fuels needed to meet the end use or uses.
"Energy storage capacity" means the nameplate capacity of
a contracted energy storage system, measured in megawatts AC.
"Energy storage duration" means the number of hours over
which an energy storage system is capable of continuously
discharging energy at its full energy storage capacity.
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for use at a later time, including, but not limited to,
electrochemical and electromechanical technologies. "Energy

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storage system" does not include technologies that require
combustion.
"Electric utility" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Equity investment eligible community" or "eligible
community" are synonymous and mean the geographic areas
throughout Illinois which would most benefit from equitable
investments by the State designed to combat discrimination.
Specifically, the eligible communities shall be defined as the
following areas:
(1) R3 Areas as established pursuant to Section 10-40
of the Cannabis Regulation and Tax Act, where residents
have historically been excluded from economic
opportunities, including opportunities in the energy
sector; and
(2) environmental justice communities, as defined by
the Illinois Power Agency pursuant to the Illinois Power
Agency Act, where residents have historically been subject
to disproportionate burdens of pollution, including
pollution from the energy sector.
"Equity eligible persons" or "eligible persons" means
persons who would most benefit from equitable investments by
the State designed to combat discrimination, specifically:
(1) persons who graduate from or are current or former
participants in the Clean Jobs Workforce Network Program,
the Clean Energy Contractor Incubator Program, the

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Illinois Climate Works Preapprenticeship Program,
Returning Residents Clean Jobs Training Program, or the
Clean Energy Primes Contractor Accelerator Program, and
the solar training pipeline and multi-cultural jobs
program created in paragraphs (a)(1) and (a)(3) of Section
16-208.12 of the Public Utilities Act;
(2) persons who are graduates of or currently enrolled
in the foster care system;
(3) persons who were formerly incarcerated;
(4) persons whose primary residence is in an equity
investment eligible community.
"Equity eligible contractor" means a business that is
majority-owned by eligible persons, or a nonprofit or
cooperative that is majority-governed by eligible persons, or
is a natural person that is an eligible person offering
personal services as an independent contractor.
"Facility" means an electric generating unit or a
co-generating unit that produces electricity along with
related equipment necessary to connect the facility to an
electric transmission or distribution system.
"General contractor" means the entity or organization with
main responsibility for the building of a construction project
and who is the party signing the prime construction contract
for the project.
"Governmental aggregator" means one or more units of local
government that individually or collectively procure

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electricity to serve residential retail electrical loads
located within its or their jurisdiction.
"High voltage direct current converter station" means the
collection of equipment that converts direct current energy
from a high voltage direct current transmission line into
alternating current using Voltage Source Conversion technology
and that is interconnected with transmission or distribution
assets located in Illinois.
"High voltage direct current renewable energy credit"
means a renewable energy credit associated with a renewable
energy resource where the renewable energy resource has
entered into a contract to transmit the energy associated with
such renewable energy credit over high voltage direct current
transmission facilities.
"High voltage direct current transmission facilities"
means the collection of installed equipment that converts
alternating current energy in one location to direct current
and transmits that direct current energy to a high voltage
direct current converter station using Voltage Source
Conversion technology. "High voltage direct current
transmission facilities" includes the high voltage direct
current converter station itself and associated high voltage
direct current transmission lines. Notwithstanding the
preceding, after September 15, 2021 (the effective date of
Public Act 102-662), an otherwise qualifying collection of
equipment does not qualify as high voltage direct current

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transmission facilities unless its developer entered into a
project labor agreement, is capable of transmitting
electricity at 525kv with an Illinois converter station
located and interconnected in the region of the PJM
Interconnection, LLC, and the system does not operate as a
public utility, as that term is defined in Section 3-105 of the
Public Utilities Act.
"Hydropower" means any method of electricity generation or
storage that results from the flow of water, including
impoundment facilities, diversion facilities, and pumped
storage facilities.
"Index price" means the real-time energy settlement price
at the applicable Illinois trading hub, such as PJM-NIHUB or
MISO-IL, for a given settlement period. "Index price" may, if
a utility-scale wind facility or a utility-scale solar
facility interconnected with an electric utility elects to use
an alternative definition, also include the monthly settlement
of the applicable seasonal qualifying facilities rate offered
by the interconnecting electric utility.
"Indexed credit" means a credit subject to a contract
described in Section 1-93.
"Indexed renewable energy credit" means a tradable credit
that represents the environmental attributes of one megawatt
hour of energy produced from a renewable energy resource, the
price of which shall be calculated by subtracting the strike
price offered by a new utility-scale wind project or a new

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utility-scale photovoltaic project from the index price in a
given settlement period.
"Indexed renewable energy credit counterparty" has the
same meaning as "public utility" as defined in Section 3-105
of the Public Utilities Act.
"Local government" means a unit of local government as
defined in Section 1 of Article VII of the Illinois
Constitution.
"Long-duration energy storage" means an energy storage
system capable of dispatching energy at its full rated
capacity for 10 or more hours.
"Long-term energy storage contract" means a contract for
the purchase of energy storage credits generated by an energy
storage system for a period of at least 15 years.
"Modernized" or "retooled" means the construction, repair,
maintenance, or significant expansion of turbines and existing
hydropower dams.
"Multi-day energy storage" means an energy storage system
capable of dispatching energy at its full rated capacity for
greater than 24 hours.
"Municipality" means a city, village, or incorporated
town.
"Municipal utility" means a public utility owned and
operated by any subdivision or municipal corporation of this
State.
"Nameplate capacity" means the aggregate inverter

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nameplate capacity in kilowatts AC. "Nameplate capacity" does
not include the capacity of an energy storage system
associated with a renewable energy resource.
"Person" means any natural person, firm, partnership,
corporation, either domestic or foreign, company, association,
limited liability company, joint stock company, or association
and includes any trustee, receiver, assignee, or personal
representative thereof.
"Project" means the planning, bidding, and construction of
a facility.
"Project labor agreement" means a pre-hire collective
bargaining agreement that covers all terms and conditions of
employment on a specific construction project and must include
the following:
(1) provisions establishing the minimum hourly wage
for each class of labor organization employee;
(2) provisions establishing the benefits and other
compensation for each class of labor organization
employee;
(3) provisions establishing that no strike or disputes
will be engaged in by the labor organization employees;
(4) provisions establishing that no lockout or
disputes will be engaged in by the general contractor
building the project; and
(5) provisions for minorities and women, as defined
under the Business Enterprise for Minorities, Women, and

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Persons with Disabilities Act, setting forth goals for
apprenticeship hours to be performed by minorities and
women and setting forth goals for total hours to be
performed by underrepresented minorities and women.
A labor organization and the general contractor building
the project shall have the authority to include other terms
and conditions as they deem necessary.
"Public utility" has the same definition as found in
Section 3-105 of the Public Utilities Act.
"Qualified combined heat and power systems" means systems
that, either simultaneously or sequentially, produce
electricity and useful thermal energy from a single fuel
source. Such systems are eligible for "renewable energy
credits" in an amount equal to its total energy output where a
renewable fuel is consumed or in an amount equal to the net
reduction in nonrenewable fuel consumed on a total energy
output basis.
"Real property" means any interest in land together with
all structures, fixtures, and improvements thereon, including
lands under water and riparian rights, any easements,
covenants, licenses, leases, rights-of-way, uses, and other
interests, together with any liens, judgments, mortgages, or
other claims or security interests related to real property.
"Renewable energy credit" means a tradable credit that
represents the environmental attributes of one megawatt hour
of energy produced from a renewable energy resource.

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"Renewable energy resources" includes energy and its
associated renewable energy credit or renewable energy credits
from wind, solar thermal energy, photovoltaic cells and
panels, biodiesel, anaerobic digestion, crops and untreated
and unadulterated organic waste biomass, and hydropower that
does not involve new construction of dams, waste heat to power
systems, or qualified combined heat and power systems. For
purposes of this Act, landfill gas produced in the State is
considered a renewable energy resource. "Renewable energy
resources" does not include the incineration or burning of
tires, garbage, general household, institutional, and
commercial waste, industrial lunchroom or office waste,
landscape waste, railroad crossties, utility poles, or
construction or demolition debris, other than untreated and
unadulterated waste wood. "Renewable energy resources" also
includes high voltage direct current renewable energy credits
and the associated energy converted to alternating current by
a high voltage direct current converter station to the extent
that: (1) the generator of such renewable energy resource
contracted with a third party to transmit the energy over the
high voltage direct current transmission facilities, and (2)
the third-party contracting for delivery of renewable energy
resources over the high voltage direct current transmission
facilities have ownership rights over the unretired associated
high voltage direct current renewable energy credit.
"Retail customer" has the same definition as found in

HB3758 - 23 - LRB104 12225 JDS 22331 b
Section 16-102 of the Public Utilities Act.
"Revenue bond" means any bond, note, or other evidence of
indebtedness issued by the Authority, the principal and
interest of which is payable solely from revenues or income
derived from any project or activity of the Agency.
"Sequester" means permanent storage of carbon dioxide by
injecting it into a saline aquifer, a depleted gas reservoir,
or an oil reservoir, directly or through an enhanced oil
recovery process that may involve intermediate storage,
regardless of whether these activities are conducted by a
clean coal facility, a clean coal SNG facility, a clean coal
SNG brownfield facility, or a party with which a clean coal
facility, clean coal SNG facility, or clean coal SNG
brownfield facility has contracted for such purposes.
"Service area" has the same definition as found in Section
16-102 of the Public Utilities Act.
"Settlement period" means the period of time utilized by
MISO and PJM and their successor organizations as the basis
for settlement calculations in the real-time energy market.
"Sourcing agreement" means (i) in the case of an electric
utility, an agreement between the owner of a clean coal
facility and such electric utility, which agreement shall have
terms and conditions meeting the requirements of paragraph (3)
of subsection (d) of Section 1-75, (ii) in the case of an
alternative retail electric supplier, an agreement between the
owner of a clean coal facility and such alternative retail

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electric supplier, which agreement shall have terms and
conditions meeting the requirements of Section 16-115(d)(5) of
the Public Utilities Act, and (iii) in case of a gas utility,
an agreement between the owner of a clean coal SNG brownfield
facility and the gas utility, which agreement shall have the
terms and conditions meeting the requirements of subsection
(h-1) of Section 9-220 of the Public Utilities Act.
"Strike price" means a contract price for energy and
renewable energy credits from a new utility-scale wind project
or a new utility-scale photovoltaic project.
"Subscriber" means a person who (i) takes delivery service
from an electric utility, and (ii) has a subscription of no
less than 200 watts to a community renewable generation
project that is located in the electric utility's service
area. No subscriber's subscriptions may total more than 40% of
the nameplate capacity of an individual community renewable
generation project. Entities that are affiliated by virtue of
a common parent shall not represent multiple subscriptions
that total more than 40% of the nameplate capacity of an
individual community renewable generation project.
"Subscription" means an interest in a community renewable
generation project expressed in kilowatts, which is sized
primarily to offset part or all of the subscriber's
electricity usage.
"Substitute natural gas" or "SNG" means a gas manufactured
by gasification of hydrocarbon feedstock, which is

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substantially interchangeable in use and distribution with
conventional natural gas.
"Total resource cost test" or "TRC test" means a standard
that is met if, for an investment in energy efficiency or
demand-response measures, the benefit-cost ratio is greater
than one. The benefit-cost ratio is the ratio of the net
present value of the total benefits of the program to the net
present value of the total costs as calculated over the
lifetime of the measures. A total resource cost test compares
the sum of avoided electric utility costs, representing the
benefits that accrue to the system and the participant in the
delivery of those efficiency measures and including avoided
costs associated with reduced use of natural gas or other
fuels, avoided costs associated with reduced water
consumption, and avoided costs associated with reduced
operation and maintenance costs, as well as other quantifiable
societal benefits, to the sum of all incremental costs of
end-use measures that are implemented due to the program
(including both utility and participant contributions), plus
costs to administer, deliver, and evaluate each demand-side
program, to quantify the net savings obtained by substituting
the demand-side program for supply resources. In calculating
avoided costs of power and energy that an electric utility
would otherwise have had to acquire, reasonable estimates
shall be included of financial costs likely to be imposed by
future regulations and legislation on emissions of greenhouse

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gases. In discounting future societal costs and benefits for
the purpose of calculating net present values, a societal
discount rate based on actual, long-term Treasury bond yields
should be used. Notwithstanding anything to the contrary, the
TRC test shall not include or take into account a calculation
of market price suppression effects or demand reduction
induced price effects.
"Utility-scale solar project" means an electric generating
facility that:
(1) generates electricity using photovoltaic cells;
and
(2) has a nameplate capacity that is greater than
5,000 kilowatts.
"Utility-scale wind project" means an electric generating
facility that:
(1) generates electricity using wind; and
(2) has a nameplate capacity that is greater than
5,000 kilowatts.
"Waste Heat to Power Systems" means systems that capture
and generate electricity from energy that would otherwise be
lost to the atmosphere without the use of additional fuel.
"Zero emission credit" means a tradable credit that
represents the environmental attributes of one megawatt hour
of energy produced from a zero emission facility.
"Zero emission facility" means a facility that: (1) is
fueled by nuclear power; and (2) is interconnected with PJM

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Interconnection, LLC or the Midcontinent Independent System
Operator, Inc., or their successors.
(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23;
103-380, eff. 1-1-24.)
(20 ILCS 3855/1-20)
Sec. 1-20. General powers and duties of the Agency.
(a) The Agency is authorized to do each of the following:
(1) Develop electricity procurement plans to ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability, for electric utilities that on December
31, 2005 provided electric service to at least 100,000
customers in Illinois and for small multi-jurisdictional
electric utilities that (A) on December 31, 2005 served
less than 100,000 customers in Illinois and (B) request a
procurement plan for their Illinois jurisdictional load.
Except as provided in paragraph (1.5) of this subsection
(a), the electricity procurement plans shall be updated on
an annual basis and shall include electricity generated
from renewable resources sufficient to achieve the
standards specified in this Act. Beginning with the
delivery year commencing June 1, 2017, develop procurement
plans to include zero emission credits generated from zero
emission facilities sufficient to achieve the standards

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specified in this Act. Beginning with the delivery year
commencing on June 1, 2022, the Agency is authorized to
develop carbon mitigation credit procurement plans to
include carbon mitigation credits generated from
carbon-free energy resources sufficient to achieve the
standards specified in this Act.
(1.5) Develop a long-term renewable resources
procurement plan in accordance with subsection (c) of
Section 1-75 of this Act for renewable energy credits in
amounts sufficient to achieve the standards specified in
this Act for delivery years commencing June 1, 2017 and
for the programs and renewable energy credits specified in
Section 1-56 of this Act. Electricity procurement plans
for delivery years commencing after May 31, 2017, shall
not include procurement of renewable energy resources.
(2) Conduct competitive procurement processes to
procure the supply resources identified in the electricity
procurement plan, pursuant to Section 16-111.5 of the
Public Utilities Act, and, for the delivery year
commencing June 1, 2017, conduct procurement processes to
procure zero emission credits from zero emission
facilities, under subsection (d-5) of Section 1-75 of this
Act. For the delivery year commencing June 1, 2022, the
Agency is authorized to conduct procurement processes to
procure carbon mitigation credits from carbon-free energy
resources, under subsection (d-10) of Section 1-75 of this

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Act.
(2.5) Beginning with the procurement for the 2017
delivery year, conduct competitive procurement processes
and implement programs to procure renewable energy credits
identified in the long-term renewable resources
procurement plan developed and approved under subsection
(c) of Section 1-75 of this Act and Section 16-111.5 of the
Public Utilities Act.
(2.10) Oversee the procurement by electric utilities
that served more than 300,000 customers in this State as
of January 1, 2019 of renewable energy credits from new
renewable energy facilities to be installed, along with
energy storage facilities, at or adjacent to the sites of
electric generating facilities that burned coal as their
primary fuel source as of January 1, 2016 in accordance
with subsection (c-5) of Section 1-75 of this Act.
(2.15) Oversee the procurement by electric utilities
of renewable energy credits from newly modernized or
retooled hydropower dams or dams that have been converted
to support hydropower generation.
(3) Develop electric generation and co-generation
facilities that use indigenous coal or renewable
resources, or both, financed with bonds issued by the
Illinois Finance Authority.
(4) Supply electricity from the Agency's facilities at
cost to one or more of the following: municipal electric

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systems, governmental aggregators, or rural electric
cooperatives in Illinois.
(5) Conduct competitive solicitations to procure
energy storage credits sufficient to achieve, at minimum,
the energy storage standard under Section 1-93.
(b) Except as otherwise limited by this Act, the Agency
has all of the powers necessary or convenient to carry out the
purposes and provisions of this Act, including without
limitation, each of the following:
(1) To have a corporate seal, and to alter that seal at
pleasure, and to use it by causing it or a facsimile to be
affixed or impressed or reproduced in any other manner.
(2) To use the services of the Illinois Finance
Authority necessary to carry out the Agency's purposes.
(3) To negotiate and enter into loan agreements and
other agreements with the Illinois Finance Authority.
(4) To obtain and employ personnel and hire
consultants that are necessary to fulfill the Agency's
purposes, and to make expenditures for that purpose within
the appropriations for that purpose.
(5) To purchase, receive, take by grant, gift, devise,
bequest, or otherwise, lease, or otherwise acquire, own,
hold, improve, employ, use, and otherwise deal in and
with, real or personal property whether tangible or
intangible, or any interest therein, within the State.
(6) To acquire real or personal property, whether

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tangible or intangible, including without limitation
property rights, interests in property, franchises,
obligations, contracts, and debt and equity securities,
and to do so by the exercise of the power of eminent domain
in accordance with Section 1-21; except that any real
property acquired by the exercise of the power of eminent
domain must be located within the State.
(7) To sell, convey, lease, exchange, transfer,
abandon, or otherwise dispose of, or mortgage, pledge, or
create a security interest in, any of its assets,
properties, or any interest therein, wherever situated.
(8) To purchase, take, receive, subscribe for, or
otherwise acquire, hold, make a tender offer for, vote,
employ, sell, lend, lease, exchange, transfer, or
otherwise dispose of, mortgage, pledge, or grant a
security interest in, use, and otherwise deal in and with,
bonds and other obligations, shares, or other securities
(or interests therein) issued by others, whether engaged
in a similar or different business or activity.
(9) To make and execute agreements, contracts, and
other instruments necessary or convenient in the exercise
of the powers and functions of the Agency under this Act,
including contracts with any person, including personal
service contracts, or with any local government, State
agency, or other entity; and all State agencies and all
local governments are authorized to enter into and do all

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things necessary to perform any such agreement, contract,
or other instrument with the Agency. No such agreement,
contract, or other instrument shall exceed 40 years.
(10) To lend money, invest and reinvest its funds in
accordance with the Public Funds Investment Act, and take
and hold real and personal property as security for the
payment of funds loaned or invested.
(11) To borrow money at such rate or rates of interest
as the Agency may determine, issue its notes, bonds, or
other obligations to evidence that indebtedness, and
secure any of its obligations by mortgage or pledge of its
real or personal property, machinery, equipment,
structures, fixtures, inventories, revenues, grants, and
other funds as provided or any interest therein, wherever
situated.
(12) To enter into agreements with the Illinois
Finance Authority to issue bonds whether or not the income
therefrom is exempt from federal taxation.
(13) To procure insurance against any loss in
connection with its properties or operations in such
amount or amounts and from such insurers, including the
federal government, as it may deem necessary or desirable,
and to pay any premiums therefor.
(14) To negotiate and enter into agreements with
trustees or receivers appointed by United States
bankruptcy courts or federal district courts or in other

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proceedings involving adjustment of debts and authorize
proceedings involving adjustment of debts and authorize
legal counsel for the Agency to appear in any such
proceedings.
(15) To file a petition under Chapter 9 of Title 11 of
the United States Bankruptcy Code or take other similar
action for the adjustment of its debts.
(16) To enter into management agreements for the
operation of any of the property or facilities owned by
the Agency.
(17) To enter into an agreement to transfer and to
transfer any land, facilities, fixtures, or equipment of
the Agency to one or more municipal electric systems,
governmental aggregators, or rural electric agencies or
cooperatives, for such consideration and upon such terms
as the Agency may determine to be in the best interest of
the residents of Illinois.
(18) To enter upon any lands and within any building
whenever in its judgment it may be necessary for the
purpose of making surveys and examinations to accomplish
any purpose authorized by this Act.
(19) To maintain an office or offices at such place or
places in the State as it may determine.
(20) To request information, and to make any inquiry,
investigation, survey, or study that the Agency may deem
necessary to enable it effectively to carry out the

HB3758 - 34 - LRB104 12225 JDS 22331 b
provisions of this Act.
(21) To accept and expend appropriations.
(22) To engage in any activity or operation that is
incidental to and in furtherance of efficient operation to
accomplish the Agency's purposes, including hiring
employees that the Director deems essential for the
operations of the Agency.
(23) To adopt, revise, amend, and repeal rules with
respect to its operations, properties, and facilities as
may be necessary or convenient to carry out the purposes
of this Act, subject to the provisions of the Illinois
Administrative Procedure Act and Sections 1-22 and 1-35 of
this Act.
(24) To establish and collect charges and fees as
described in this Act.
(25) To conduct competitive gasification feedstock
procurement processes to procure the feedstocks for the
clean coal SNG brownfield facility in accordance with the
requirements of Section 1-78 of this Act.
(26) To review, revise, and approve sourcing
agreements and mediate and resolve disputes between gas
utilities and the clean coal SNG brownfield facility
pursuant to subsection (h-1) of Section 9-220 of the
Public Utilities Act.
(27) To request, review and accept proposals, execute
contracts, purchase renewable energy credits and otherwise

HB3758 - 35 - LRB104 12225 JDS 22331 b
dedicate funds from the Illinois Power Agency Renewable
Energy Resources Fund to create and carry out the
objectives of the Illinois Solar for All Program in
accordance with Section 1-56 of this Act.
(28) To ensure Illinois residents and business benefit
from programs administered by the Agency and are properly
protected from any deceptive or misleading marketing
practices by participants in the Agency's programs and
procurements.
(29) To request, review, and accept proposals; to
execute contracts; and to procure energy storage credits.
(c) In conducting the procurement of electricity or other
products, beginning January 1, 2022, the Agency shall not
procure any products or services from persons or organizations
that are in violation of the Displaced Energy Workers Bill of
Rights, as provided under the Energy Community Reinvestment
Act at the time of the procurement event or fail to comply the
labor standards established in subparagraph (Q) of paragraph
(1) of subsection (c) of Section 1-75.
(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
(20 ILCS 3855/1-75)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,

HB3758 - 36 - LRB104 12225 JDS 22331 b
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that
on December 31, 2005 provided electric service to at least
100,000 customers in Illinois. Beginning with the delivery
year commencing on June 1, 2017, the Planning and Procurement
Bureau shall develop plans and processes for the procurement
of zero emission credits from zero emission facilities in
accordance with the requirements of subsection (d-5) of this
Section. Beginning on the effective date of this amendatory
Act of the 102nd General Assembly, the Planning and
Procurement Bureau shall develop plans and processes for the
procurement of carbon mitigation credits from carbon-free
energy resources in accordance with the requirements of
subsection (d-10) of this Section. The Planning and
Procurement Bureau shall also develop procurement plans and
conduct competitive procurement processes in accordance with
the requirements of Section 16-111.5 of the Public Utilities
Act for the eligible retail customers of small
multi-jurisdictional electric utilities that (i) on December
31, 2005 served less than 100,000 customers in Illinois and
(ii) request a procurement plan for their Illinois
jurisdictional load. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Agency to prepare a

HB3758 - 37 - LRB104 12225 JDS 22331 b
procurement plan for their Illinois jurisdictional load. For
the purposes of this Section, the term "eligible retail
customers" has the same definition as found in Section
16-111.5(a) of the Public Utilities Act.
Beginning with the plan or plans to be implemented in the
2017 delivery year, the Agency shall no longer include the
procurement of renewable energy resources in the annual
procurement plans required by this subsection (a), except as
provided in subsection (q) of Section 16-111.5 of the Public
Utilities Act, and shall instead develop a long-term renewable
resources procurement plan in accordance with subsection (c)
of this Section and Section 16-111.5 of the Public Utilities
Act.
In accordance with subsection (c-5) of this Section, the
Planning and Procurement Bureau shall oversee the procurement
by electric utilities that served more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new utility-scale solar projects to be
installed, along with energy storage facilities, at or
adjacent to the sites of electric generating facilities that,
as of January 1, 2016, burned coal as their primary fuel
source.
(1) The Agency shall each year, beginning in 2008, as
needed, issue a request for qualifications for experts or
expert consulting firms to develop the procurement plans
in accordance with Section 16-111.5 of the Public

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Utilities Act. In order to qualify an expert or expert
consulting firm must have:
(A) direct previous experience assembling
large-scale power supply plans or portfolios for
end-use customers;
(B) an advanced degree in economics, mathematics,
engineering, risk management, or a related area of
study;
(C) 10 years of experience in the electricity
sector, including managing supply risk;
(D) expertise in wholesale electricity market
rules, including those established by the Federal
Energy Regulatory Commission and regional transmission
organizations;
(E) expertise in credit protocols and familiarity
with contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and
inappropriate bias for or against potential bidders or
the affected electric utilities.
(2) The Agency shall each year, as needed, issue a
request for qualifications for a procurement administrator
to conduct the competitive procurement processes in
accordance with Section 16-111.5 of the Public Utilities
Act. In order to qualify an expert or expert consulting

HB3758 - 39 - LRB104 12225 JDS 22331 b
firm must have:
(A) direct previous experience administering a
large-scale competitive procurement process;
(B) an advanced degree in economics, mathematics,
engineering, or a related area of study;
(C) 10 years of experience in the electricity
sector, including risk management experience;
(D) expertise in wholesale electricity market
rules, including those established by the Federal
Energy Regulatory Commission and regional transmission
organizations;
(E) expertise in credit and contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and
inappropriate bias for or against potential bidders or
the affected electric utilities.
(3) The Agency shall provide affected utilities and
other interested parties with the lists of qualified
experts or expert consulting firms identified through the
request for qualifications processes that are under
consideration to develop the procurement plans and to
serve as the procurement administrator. The Agency shall
also provide each qualified expert's or expert consulting
firm's response to the request for qualifications. All
information provided under this subparagraph shall also be

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provided to the Commission. The Agency may provide by rule
for fees associated with supplying the information to
utilities and other interested parties. These parties
shall, within 5 business days, notify the Agency in
writing if they object to any experts or expert consulting
firms on the lists. Objections shall be based on:
(A) failure to satisfy qualification criteria;
(B) identification of a conflict of interest; or
(C) evidence of inappropriate bias for or against
potential bidders or the affected utilities.
The Agency shall remove experts or expert consulting
firms from the lists within 10 days if there is a
reasonable basis for an objection and provide the updated
lists to the affected utilities and other interested
parties. If the Agency fails to remove an expert or expert
consulting firm from a list, an objecting party may seek
review by the Commission within 5 days thereafter by
filing a petition, and the Commission shall render a
ruling on the petition within 10 days. There is no right of
appeal of the Commission's ruling.
(4) The Agency shall issue requests for proposals to
the qualified experts or expert consulting firms to
develop a procurement plan for the affected utilities and
to serve as procurement administrator.
(5) The Agency shall select an expert or expert
consulting firm to develop procurement plans based on the

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proposals submitted and shall award contracts of up to 5
years to those selected.
(6) The Agency shall select an expert or expert
consulting firm, with approval of the Commission, to serve
as procurement administrator based on the proposals
submitted. If the Commission rejects, within 5 days, the
Agency's selection, the Agency shall submit another
recommendation within 3 days based on the proposals
submitted. The Agency shall award a 5-year contract to the
expert or expert consulting firm so selected with
Commission approval.
(b) The experts or expert consulting firms retained by the
Agency shall, as appropriate, prepare procurement plans, and
conduct a competitive procurement process as prescribed in
Section 16-111.5 of the Public Utilities Act, to ensure
adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least
100,000 customers in the State of Illinois, and for eligible
Illinois retail customers of small multi-jurisdictional
electric utilities that (i) on December 31, 2005 served less
than 100,000 customers in Illinois and (ii) request a
procurement plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.

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(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
June 1, 2017 (the effective date of Public Act 99-906).
The Agency shall review, and may revise on an expedited
basis, the long-term renewable resources procurement plan
at least every 2 years, which shall be conducted in
conjunction with the procurement plan under Section
16-111.5 of the Public Utilities Act to the extent
practicable to minimize administrative expense. No later
than 120 days after the effective date of this amendatory
Act of the 103rd General Assembly, the Agency shall
release for comment a revision to the long-term renewable
resources procurement plan, updating elements of the most
recently approved plan as needed to comply with this
amendatory Act of the 103rd General Assembly, and any
long-term renewable resources procurement plan update
published by the Agency but not yet approved by the
Illinois Commerce Commission shall be withdrawn. The
long-term renewable resources procurement plans shall be
subject to review and approval by the Commission under
Section 16-111.5 of the Public Utilities Act.
(B) Subject to subparagraph (F) of this paragraph (1),

HB3758 - 43 - LRB104 12225 JDS 22331 b
the long-term renewable resources procurement plan shall
attempt to meet the goals for procurement of renewable
energy credits at levels of at least the following overall
percentages: 13% by the 2017 delivery year; increasing by
at least 1.5% each delivery year thereafter to at least
25% by the 2025 delivery year; increasing by at least 3%
each delivery year thereafter to at least 40% by the 2030
delivery year, and continuing at no less than 40% for each
delivery year thereafter. The Agency shall attempt to
procure 50% by delivery year 2040. The Agency shall
determine the annual increase between delivery year 2030
and delivery year 2040, if any, taking into account energy
demand, other energy resources, and other public policy
goals. In the event of a conflict between these goals and
the new wind, new photovoltaic, and hydropower procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1), the long-term plan
shall prioritize compliance with the new wind, new
photovoltaic, and hydropower procurement requirements
described in items (i) through (iii) of subparagraph (C)
of this paragraph (1) over the annual percentage targets
described in this subparagraph (B). The Agency shall not
comply with the annual percentage targets described in
this subparagraph (B) by procuring renewable energy
credits that are unlikely to lead to the development of
new renewable resources or new, modernized, or retooled

HB3758 - 44 - LRB104 12225 JDS 22331 b
hydropower facilities.
For the delivery year beginning June 1, 2017, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 13% of each utility's load for eligible retail
customers and 13% of the applicable portion of each
utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 50%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2018, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 14.5% of each utility's load for eligible retail
customers and 14.5% of the applicable portion of each
utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 75%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2019, and for
each year thereafter, the procurement plans shall attempt
to include, subject to the prioritization outlined in this
subparagraph (B), cost-effective renewable energy
resources equal to a minimum percentage of each utility's

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load for all retail customers as follows: 16% by June 1,
2019; increasing by 1.5% each year thereafter to 25% by
June 1, 2025; and 25% by June 1, 2026; increasing by at
least 3% each delivery year thereafter to at least 40% by
the 2030 delivery year, and continuing at no less than 40%
for each delivery year thereafter. The Agency shall
attempt to procure 50% by delivery year 2040. The Agency
shall determine the annual increase between delivery year
2030 and delivery year 2040, if any, taking into account
energy demand, other energy resources, and other public
policy goals.
For each delivery year, the Agency shall first
recognize each utility's obligations for that delivery
year under existing contracts. Any renewable energy
credits under existing contracts, including renewable
energy credits as part of renewable energy resources,
shall be used to meet the goals set forth in this
subsection (c) for the delivery year.
(C) The long-term renewable resources procurement plan
described in subparagraph (A) of this paragraph (1) shall
include the procurement of renewable energy credits from
new projects pursuant to the following terms:
(i) At least 10,000,000 renewable energy credits
delivered annually by the end of the 2021 delivery
year, and increasing ratably to reach 45,000,000
renewable energy credits delivered annually from new

HB3758 - 46 - LRB104 12225 JDS 22331 b
wind and solar projects, from repowered wind projects,
or from retooled hydropower facilities by the end of
delivery year 2030 such that the goals in subparagraph
(B) of this paragraph (1) are met entirely by
procurements of renewable energy credits from new wind
and photovoltaic projects. Of that amount, to the
extent possible, the Agency shall endeavor to procure
45% from new and repowered wind and hydropower
projects and shall procure at least 55% from
photovoltaic projects. Of the amount to be procured
from photovoltaic projects, the Agency shall procure:
at least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
generation devices or community renewable generation
projects; at least 47% from utility-scale solar
projects; at least 3% from brownfield site
photovoltaic projects that are not community renewable
generation projects. The Agency may propose
adjustments to these percentages, including
establishing percentage-based goals for the
procurement of renewable energy credits from retooled
hydropower facilities and repowered wind projects
through its long-term renewable resources plan
described in subparagraph (A) of this paragraph (1),
as necessary, based on developer interest, market

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conditions, budget considerations, and other material
factors.
In developing the long-term renewable resources
procurement plan, the Agency shall consider other
approaches, in addition to competitive procurements,
that can be used to procure renewable energy credits
from brownfield site photovoltaic projects and thereby
help return blighted or contaminated land to
productive use while enhancing public health and the
well-being of Illinois residents, including those in
environmental justice communities, as defined using
existing methodologies and findings used by the Agency
and its Administrator in its Illinois Solar for All
Program. The Agency shall also consider other
approaches, in addition to competitive procurements,
to procure renewable energy credits from new and
existing hydropower facilities to support the
development and maintenance of these facilities. The
Agency shall explore options to convert existing dams
but shall not consider approaches to develop new dams
where they do not already exist. To encourage
continued operation of utility-scale wind projects,
the Agency shall consider and may propose other
approaches in addition to competitive procurements to
procure renewable energy credits from repowered wind
projects.

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(ii) In any given delivery year, if forecasted
expenses are less than the maximum budget available
under subparagraph (E) of this paragraph (1), the
Agency shall continue to procure new renewable energy
credits until that budget is exhausted in the manner
outlined in item (i) of this subparagraph (C).
(iii) For purposes of this Section:
"New wind projects" means wind renewable energy
facilities that are energized after June 1, 2017 for
the delivery year commencing June 1, 2017.
"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized after
June 1, 2017. Photovoltaic projects developed under
Section 1-56 of this Act shall not apply towards the
new photovoltaic project requirements in this
subparagraph (C).
For purposes of calculating whether the Agency has
procured enough new wind and solar renewable energy
credits required by this subparagraph (C), renewable
energy facilities that have a multi-year renewable
energy credit delivery contract with the utility
through at least delivery year 2030 shall be
considered new, however no renewable energy credits
from contracts entered into before June 1, 2021 shall
be used to calculate whether the Agency has procured
the correct proportion of new wind and new solar

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contracts described in this subparagraph (C) for
delivery year 2021 and thereafter.
(D) Renewable energy credits shall be cost effective.
For purposes of this subsection (c), "cost effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in subparagraph
(E) of this paragraph (1) to be exceeded and, for
renewable energy credits procured through a competitive
procurement event, do not exceed benchmarks based on
market prices for like products in the region. For
purposes of this subsection (c), "like products" means
contracts for renewable energy credits from the same or
substantially similar technology, same or substantially
similar vintage (new or existing), the same or
substantially similar quantity, and the same or
substantially similar contract length and structure.
Benchmarks shall reflect development, financing, or
related costs resulting from requirements imposed through
other provisions of State law, including, but not limited
to, requirements in subparagraphs (P) and (Q) of this
paragraph (1) and the Renewable Energy Facilities
Agricultural Impact Mitigation Act. Confidential
benchmarks shall be developed by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval. If price

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benchmarks for like products in the region are not
available, the procurement administrator shall establish
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. Prior to a procurement, the Agency
shall ensure that the procurement administrator considers
comments from potential bidders regarding inputs,
structure, and methodology of the benchmark for the
procurement, including costs and risks of development,
construction, financing, or other categories as determined
by the Agency. In the request for comments on the
benchmark, the procurement administrator shall provide all
potential bidders with sufficient information about the
structure, methodology, and inputs for previous benchmarks
to allow for informed comment. The benchmarks in this
Section shall not be used to curtail or otherwise reduce
contractual obligations entered into by or through the
Agency prior to June 1, 2017 (the effective date of Public
Act 99-906).
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources
for a particular year commencing prior to June 1, 2017
shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for

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delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) delivered by the electric utility in the
delivery year ending immediately prior to the procurement,
to all retail customers in its service territory. For
purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (c), the total amount paid for
electric service includes without limitation amounts paid
for supply, transmission, capacity, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(c), and except as provided in subparagraph (E-5) of
paragraph (1) of this subsection (c), the total of
renewable energy resources procured under the procurement
plan for any single year shall be subject to the
limitations of this subparagraph (E). Such procurement
shall be reduced for all retail customers based on the
amount necessary to limit the annual estimated average net
increase due to the costs of these resources included in
the amounts paid by eligible retail customers in
connection with electric service to no more than 4.25% of
the amount paid per kilowatthour by those customers during

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the year ending May 31, 2009. To arrive at a maximum dollar
amount of renewable energy resources to be procured for
the particular delivery year, the resulting per
kilowatthour amount shall be applied to the actual amount
of kilowatthours of electricity delivered, or applicable
portion of such amount as specified in paragraph (1) of
this subsection (c), as applicable, by the electric
utility in the delivery year immediately prior to the
procurement to all retail customers in its service
territory. The calculations required by this subparagraph
(E) shall be made only once for each delivery year at the
time that the renewable energy resources are procured.
Once the determination as to the amount of renewable
energy resources to procure is made based on the
calculations set forth in this subparagraph (E) and the
contracts procuring those amounts are executed, no
subsequent rate impact determinations shall be made and no
adjustments to those contract amounts shall be allowed. As
provided in subparagraph (E-5) of paragraph (1) of this
subsection (c), the seller shall be entitled to full,
prompt, and uninterrupted payment under the applicable
contract notwithstanding the application of this
subparagraph (E), and all All costs incurred under such
contracts shall be fully recoverable by the electric
utility as provided in this Section.
(E-5) If, for a particular delivery year, the

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limitation on the amount of renewable energy resources to
be procured, as calculated pursuant to subparagraph (E) of
paragraph (1) of this subsection (c), would result in an
insufficient collection of funds to fully pay amounts due
to a seller under existing contracts executed under this
Section or executed under Section 1-56 of this Act, then
the following provisions shall apply to ensure full and
uninterrupted payment is made to such seller or sellers:
(i) If the electric utility has retained unspent
funds in an interest-bearing account as prescribed in
subsection (k) of Section 16-108 of the Public
Utilities Act, then the utility shall use those funds
to remit full payment to the sellers to ensure prompt
and uninterrupted payment of existing contractual
obligation.
(ii) If the funds described in item (i) of this
subparagraph (E-5) are insufficient to satisfy all
existing contractual obligations, then the electric
utility shall, nonetheless, remit full payment to the
sellers to ensure prompt and uninterrupted payment of
existing contractual obligations, provided that the
full costs shall be recoverable by the utility in
accordance with part (ee) of item (iv) of this
subparagraph (E-5).
(iii) The Agency shall promptly notify the
Commission that existing contractual obligations are

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reasonably expected to exceed the maximum collection
authorized under subparagraph (E) of paragraph (1) of
this subsection (c) for the applicable delivery year.
The Agency shall also explain and confirm how the
operation of items (i) and (ii) of this subparagraph
(E-5) ensures that the electric utility will continue
to make prompt and uninterrupted payment under
existing contractual obligations. The Agency shall
provide this information to the Commission through a
notice filed in the Commission docket approving the
Agency's operative Long-Term Renewable Resources
Procurement Plan that includes the applicable delivery
year.
(iv) The Agency shall suspend or reduce new
contract awards for the procurement of renewable
energy credits until an Agency determination is made
under subparagraph (E) that additional procurements
would not cause the rate impact limitation of
subparagraph (E) to be exceeded. At least once
annually after the notice provided for in item (iii)
of this subparagraph (E-5) is made, the Agency shall
analyze existing contract obligations, projected
prices for indexed renewable energy credit contracts
executed under item (v) of subparagraph (G) of
paragraph (1) of subsection (c) of Section 1-75 of
this Act, and expected collections authorized under

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subparagraph (E) to determine whether and to what
extent the limitations of subparagraph (E) would be
exceeded by additional renewable energy credit
procurement contract awards.
(aa) If the Agency determines that additional
renewable energy credit procurement contract
awards could be made without exceeding the
limitations of subparagraph (E), then the
procurements shall be authorized at a scale
determined not to exceed the limitations of
subparagraph (E) in a manner consistent with the
priorities of this Section.
(bb) If the Agency determines that additional
renewable energy credit procurement contract
awards cannot be made without exceeding the
limitations of subparagraph (E), then the Agency
shall suspend any new contract awards for the
procurement of renewable energy credits until a
new rate impact determination is made under
subparagraph (E).
(cc) Agency determinations made under this
item (iv) shall be detailed and comprehensive and,
if not made through the Agency's Long-Term
Renewable Resources Procurement Plan, shall be
filed as a compliance filing in the most recent
docketed proceeding approving the Agency's

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Long-Term Renewable Resources Procurement Plan.
(dd) With respect to the procurement of
renewable energy credits authorized through
programs administered under subsection (b) of
Section 1-56 and subparagraphs (K) through (M) of
paragraph (1) of subsection (k) of Section 1-75 of
this Act, the award of contracts for the
procurement of renewable energy credits shall be
suspended or reduced 12 months following the
notice provided for under item (iii) of this
subparagraph (E-5) is made.
(ee) The contract shall provide that, so long
as at least one of: (i) the cost recovery
mechanisms referenced in subsection (k) of Section
16-108 and subsection (l) of Section 16-111.5 of
the Public Utilities Act remains in full force
without limitation or (ii) the utility is
otherwise authorized and or entitled to full,
prompt, and uninterrupted recovery of its costs
through any other mechanism, then such seller
shall be entitled to full, prompt, and
uninterrupted payment under the applicable
contract notwithstanding the application of this
subparagraph (E).
(F) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this

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

HB3758 - 58 - LRB104 12225 JDS 22331 b
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June
1, 2019, if available, but not later than June 1, 2021,
unless the project has delays in the establishment of
an operating interconnection with the applicable
transmission or distribution system as a result of the
actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. Payments to
suppliers of renewable energy credits shall commence
upon delivery. Renewable energy credits procured under
this initial procurement shall be included in the
Agency's long-term plan and shall apply to all
renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
solar projects and brownfield site photovoltaic
projects within one year after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new

HB3758 - 59 - LRB104 12225 JDS 22331 b
utility-scale solar projects and brownfield site
photovoltaic projects to begin delivery on June 1,
2019, if available, but not later than June 1, 2021,
unless the project has delays in the establishment of
an operating interconnection with the applicable
transmission or distribution system as a result of the
actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. The Agency may
structure this initial procurement in one or more
discrete procurement events. Payments to suppliers of
renewable energy credits shall commence upon delivery.
Renewable energy credits procured under this initial
procurement shall be included in the Agency's
long-term plan and shall apply to all renewable energy
goals in this subsection (c).
(iii) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources
procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
conduct at least one subsequent forward procurement
for renewable energy credits from new utility-scale
wind projects, new utility-scale solar projects, and
new brownfield site photovoltaic projects within 240
days after the effective date of this amendatory Act

HB3758 - 60 - LRB104 12225 JDS 22331 b
of the 102nd General Assembly in quantities necessary
to meet the requirements of subparagraph (C) of this
paragraph (1) through the delivery year beginning June
1, 2021.
(iv) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources
procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
open capacity for each category in the Adjustable
Block program within 90 days after the effective date
of this amendatory Act of the 102nd General Assembly
manner:
(1) The Agency shall open the first block of
annual capacity for the category described in item
(i) of subparagraph (K) of this paragraph (1). The
first block of annual capacity for item (i) shall
be for at least 75 megawatts of total nameplate
capacity. The price of the renewable energy credit
for this block of capacity shall be 4% less than
the price of the last open block in this category.
Projects on a waitlist shall be awarded contracts
first in the order in which they appear on the
waitlist. Notwithstanding anything to the
contrary, for those renewable energy credits that
qualify and are procured under this subitem (1) of
this item (iv), the renewable energy credit

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

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

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

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

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

HB3758 - 66 - LRB104 12225 JDS 22331 b
applicant firms no later than 90 days after
the effective date of this amendatory Act of
the 102nd General Assembly.
(D) Applicant firms shall submit their
portfolio of projects used to satisfy those
contract awards no less than 90 days after the
Agency's announcement. The total nameplate
capacity of all projects used to satisfy that
portfolio shall be no greater than the
Agency's nameplate capacity award amount
associated with that applicant firm. An
applicant firm may decline, in whole or in
part, its nameplate capacity award without
penalty, with such unmet capacity rolled over
to the next block opening for project
selection under item (iii) of subparagraph (K)
of this subsection (c). Any projects not
included in an applicant firm's portfolio may
reapply without prejudice upon the next block
reopening for project selection under item
(iii) of subparagraph (K) of this subsection
(c).
(E) The renewable energy credit delivery
contract shall be subject to the contract and
payment terms outlined in item (iv) of
subparagraph (L) of this subsection (c).

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

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

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

HB3758 - 70 - LRB104 12225 JDS 22331 b
that is approved as of the effective date of this
amendatory Act of the 102nd General Assembly.
Projects in this category shall be subject to the
contract terms outlined in item (iii) of
subsection (L) of this paragraph (1).
(6) The Agency shall open the first blocks of
annual capacity for the category described in item
(vi) of subparagraph (K) of this paragraph (1),
with allocations of capacity within the block
generally matching the historical share of block
capacity allocated between the category described
in items (i) and (ii) of subparagraph (K) of this
paragraph (1). The first two blocks of annual
capacity for item (vi) shall be for at least 75
megawatts of total nameplate capacity. The price
of renewable energy credits for the blocks of
capacity shall be 4% less than the price of the
last open blocks in the categories described in
items (i) and (ii) of subparagraph (K) of this
paragraph (1). Pricing for future blocks of annual
capacity for this category may be adjusted in the
Agency's second revision to its Long-Term
Renewable Resources Procurement Plan. Projects in
this category shall be subject to the applicable
contract terms outlined in items (ii) and (iii) of
subparagraph (L) of this paragraph (1).

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

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established under subparagraph (E) for indexed
renewable energy credit procurements for each year
of the term of such contracts, which must have a
minimum tenure of 20 calendar years, the
procurement administrator, Agency, Commission
staff, and procurement monitor shall quantify the
annual cost of the contract by utilizing an
industry-standard, third-party forward price curve
for energy at the appropriate hub or load zone,
including the estimated magnitude and timing of
the price effects related to federal carbon
controls. Each forward price curve shall contain a
specific value of the forecasted market price of
electricity for each annual delivery year of the
contract. For procurement planning purposes, the
impact on the annual budget for the cost of
indexed renewable energy credits for each delivery
year shall be determined as the expected annual
contract expenditure for that year, equaling the
difference between (i) the sum across all relevant
contracts of the applicable strike price
multiplied by contract quantity and (ii) the sum
across all relevant contracts of the forward price
curve for the applicable load zone for that year
multiplied by contract quantity. The contracting
utility shall not assume an obligation in excess

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of the estimated annual cost of the contracts for
indexed renewable energy credits. Forward curves
shall be revised on an annual basis as updated
forward price curves are released and filed with
the Commission in the proceeding approving the
Agency's most recent long-term renewable resources
procurement plan. If the expected contract spend
is higher or lower than the total quantity of
contracts multiplied by the forward price curve
value for that year, the forward price curve shall
be updated by the procurement administrator, in
consultation with the Agency, Commission staff,
and procurement monitors, using then-currently
available price forecast data and additional
budget dollars shall be obligated or reobligated
as appropriate.
(4) To ensure that indexed renewable energy
credit prices remain predictable and affordable,
the Agency may consider the institution of a price
collar on REC prices paid under indexed renewable
energy credit procurements establishing floor and
ceiling REC prices applicable to indexed REC
contract prices. Any price collars applicable to
indexed REC procurements shall be proposed by the
Agency through its long-term renewable resources
procurement plan.

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(vi) All procurements under this subparagraph (G),
including the procurement of renewable energy credits
from hydropower facilities, shall comply with the
geographic requirements in subparagraph (I) of this
paragraph (1) and shall follow the procurement
processes and procedures described in this Section and
Section 16-111.5 of the Public Utilities Act to the
extent practicable, and these processes and procedures
may be expedited to accommodate the schedule
established by this subparagraph (G). To ensure the
successful development of new utility-scale solar
projects and new utility-scale wind projects for
procurements under items (i), (ii), (iii), and (v) of
this subparagraph (G), a winning bidder or the current
seller under contract countersigned by an electric
utility counterparty may petition the Commission to
revise the terms in the contract. Prior to such
petition, upon request by the winning bidder or
seller, the Agency shall negotiate directly with the
winning bidder or seller. If following the direct
negotiations, the Agency and the winning bidder reach
an agreement on amended terms or strike price and the
Agency finds that the amended terms or strike price
reflect a change in circumstances since the date of
the bid based on circumstances unforeseeable at the
time of the bid, upon petition by the winning bidder or

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current seller, the Commission shall issue an order
directing the utility counterparty to execute a form
amendment drafted by the Agency with the revised terms
or the new strike price. The Agency shall provide the
amendment to the utility within 15 business days after
the Commission's order and the utility buyer shall
execute the amendment not more than 7 calendar days
after delivery by the Agency. The Agency shall develop
the form amendment following comment by interested
parties.
(vii) On and after the effective date of this
amendatory Act of the 103rd General Assembly, for all
procurements of renewable energy credits from
hydropower facilities, the Agency shall establish
contract terms designed to optimize existing
hydropower facilities through modernization or
retooling and establish new hydropower facilities at
existing dams. Procurements made under this item (vii)
shall prioritize projects located in designated
environmental justice communities, as defined in
subsection (b) of Section 1-56 of this Act, or in
projects located in units of local government with
median incomes that do not exceed 82% of the median
income of the State.
(H) The procurement of renewable energy resources for
a given delivery year shall be reduced as described in

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

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

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For delivery years beginning June 1, 2019 and
each year thereafter, the maximum amount of
renewable energy credits to be supplied by an
alternative retail electric supplier under this
subparagraph (H) shall be 68% multiplied by 50%
multiplied by 16% multiplied by the amount of
metered electricity (megawatt-hours) delivered by
the alternative retail electric supplier to
Illinois retail customers during the delivery year
ending May 31, 2016, provided that the 16% value
shall increase by 1.5% each delivery year
thereafter to 25% by the delivery year beginning
June 1, 2025, and thereafter the 25% value shall
apply to each delivery year.
For each delivery year, the total amount of
renewable energy credits supplied by all alternative
retail electric suppliers under this subparagraph (H)
shall not exceed 9% of the Illinois target renewable
energy credit quantity. The Illinois target renewable
energy credit quantity for the delivery year beginning
June 1, 2018 is 14.5% multiplied by the total amount of
metered electricity (megawatt-hours) delivered in the
delivery year immediately preceding that delivery
year, provided that the 14.5% shall increase by 1.5%
each delivery year thereafter to 25% by the delivery
year beginning June 1, 2025, and thereafter the 25%

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

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

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

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

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costs of these units are recovered. As long as a
generating unit or an identifiable portion of a generating
unit has not had and does not have its costs recovered
through rates regulated by this State or any other state,
HVDC renewable energy credits associated with that
generating unit or identifiable portion thereof shall be
eligible to be counted toward the renewable energy
requirements of this subsection (c).
(K) The long-term renewable resources procurement plan
developed by the Agency in accordance with subparagraph
(A) of this paragraph (1) shall include an Adjustable
Block program for the procurement of renewable energy
credits from new photovoltaic projects that are
distributed renewable energy generation devices or new
photovoltaic community renewable generation projects. The
Adjustable Block program shall be generally designed to
provide for the steady, predictable, and sustainable
growth of new solar photovoltaic development in Illinois.
To this end, except as otherwise provided in subparagraph
(viii) of this paragraph (K), the Adjustable Block program
shall provide a transparent annual schedule of prices and
quantities to enable the photovoltaic market to scale up
and for renewable energy credit prices to adjust at a
predictable rate over time. The prices set by the
Adjustable Block program can be reflected as a set value
or as the product of a formula.

HB3758 - 84 - LRB104 12225 JDS 22331 b
The Adjustable Block program shall include for each
category of eligible projects for each delivery year: a
single block of nameplate capacity, a price for renewable
energy credits within that block, and the terms and
conditions for securing a spot on a waitlist once the
block is fully committed or reserved. Except as outlined
below, the waitlist of projects in a given year will carry
over to apply to the subsequent year when another block is
opened. Only projects energized on or after June 1, 2017
shall be eligible for the Adjustable Block program. For
each category for each delivery year the Agency shall
determine the amount of generation capacity in each block,
and the purchase price for each block, provided that the
purchase price provided and the total amount of generation
in all blocks for all categories shall be sufficient to
meet the goals in this subsection (c). The Agency shall
strive to issue a single block sized to provide for
stability and market growth. The Agency shall establish
program eligibility requirements that ensure that projects
that enter the program are sufficiently mature to indicate
a demonstrable path to completion. The Agency may
periodically review its prior decisions establishing the
amount of generation capacity in each block, and the
purchase price for each block, and may propose, on an
expedited basis, changes to these previously set values,
including but not limited to redistributing these amounts

HB3758 - 85 - LRB104 12225 JDS 22331 b
and the available funds as necessary and appropriate,
subject to Commission approval as part of the periodic
plan revision process described in Section 16-111.5 of the
Public Utilities Act. The Agency may define different
block sizes, purchase prices, or other distinct terms and
conditions for projects located in different utility
service territories if the Agency deems it necessary to
meet the goals in this subsection (c).
The Adjustable Block program shall include the
following categories in at least the following amounts:
(i) At least 20% from distributed renewable energy
generation devices with a nameplate capacity of no
more than 25 kilowatts.
(ii) At least 20% from distributed renewable
energy generation devices with a nameplate capacity of
more than 25 kilowatts and no more than 5,000
kilowatts. The Agency may create sub-categories within
this category to account for the differences between
projects for small commercial customers, large
commercial customers, and public or non-profit
customers.
(iii) At least 30% from photovoltaic community
renewable generation projects. Capacity for this
category for the first 2 delivery years after the
effective date of this amendatory Act of the 102nd
General Assembly shall be allocated to waitlist

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projects as provided in paragraph (3) of item (iv) of
subparagraph (G). Starting in the third delivery year
after the effective date of this amendatory Act of the
102nd General Assembly or earlier if the Agency
determines there is additional capacity needed for to
meet previous delivery year requirements, the
following shall apply:
(1) to advance the interests of all ratepayers
in timely development of community renewable
generation projects powered by solar photovoltaics
procured under this Act, the Agency shall select
projects on a first-come, first-serve basis; ,
however, the Agency shall, for applications on or
after the effective date of this amendatory Act of
the 104th General Assembly, may suggest additional
methods to prioritize projects according to this
item (1). Prioritization methods shall be clear
and changes to those methods shall not hinder the
steady, predictable, and sustainable growth of
projects under this subsection. The Agency shall
ensure any project characteristics incentivized by
the prioritization method are aligned with the
findings of this Act and the price of the
associated renewable energy credit adequately
compensates the additional costs that may be
imposed on a project that are submitted at the

HB3758 - 87 - LRB104 12225 JDS 22331 b
same time;
(2) projects shall have subscriptions of 25 kW
or less for at least 50% of the facility's
nameplate capacity and the Agency shall price the
renewable energy credits with that as a factor;
(3) projects shall not be colocated with one
or more other community renewable generation
projects, as defined in the Agency's first revised
long-term renewable resources procurement plan
approved by the Commission on February 18, 2020,
such that the aggregate nameplate capacity exceeds
5,000 kilowatts; and
(4) projects greater than 2 MW may not apply
until after the approval of the Agency's revised
Long-Term Renewable Resources Procurement Plan
after the effective date of this amendatory Act of
the 102nd General Assembly.
(iv) At least 15% from distributed renewable
generation devices or photovoltaic community renewable
generation projects installed on public school land.
The Agency may create subcategories within this
category to account for the differences between
project size or location. Projects located within
environmental justice communities or within
Organizational Units that fall within Tier 1 or Tier 2
shall be given priority. Each of the Agency's periodic

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updates to its long-term renewable resources
procurement plan to incorporate the procurement
described in this subparagraph (iv) shall also include
the proposed quantities or blocks, pricing, and
contract terms applicable to the procurement as
indicated herein. In each such update and procurement,
the Agency shall set the renewable energy credit price
and establish payment terms for the renewable energy
credits procured pursuant to this subparagraph (iv)
that make it feasible and affordable for public
schools to install photovoltaic distributed renewable
energy devices on their premises, including, but not
limited to, those public schools subject to the
prioritization provisions of this subparagraph. For
the purposes of this item (iv):
"Environmental Justice Community" shall have the
same meaning set forth in the Agency's long-term
renewable resources procurement plan;
"Organization Unit", "Tier 1" and "Tier 2" shall
have the meanings set for in Section 18-8.15 of the
School Code;
"Public schools" shall have the meaning set forth
in Section 1-3 of the School Code and includes public
institutions of higher education, as defined in the
Board of Higher Education Act.
(v) At least 5% from community-driven community

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solar projects intended to provide more direct and
tangible connection and benefits to the communities
which they serve or in which they operate and,
additionally, to increase the variety of community
solar locations, models, and options in Illinois. As
part of its long-term renewable resources procurement
plan, the Agency shall develop selection criteria for
projects participating in this category. Nothing in
this Section shall preclude the Agency from creating a
selection process that maximizes community ownership
and community benefits in selecting projects to
receive renewable energy credits. Selection criteria
shall include:
(1) community ownership or community
wealth-building;
(2) additional direct and indirect community
benefit, beyond project participation as a
subscriber, including, but not limited to,
economic, environmental, social, cultural, and
physical benefits;
(3) meaningful involvement in project
organization and development by community members
or nonprofit organizations or public entities
located in or serving the community;
(4) engagement in project operations and
management by nonprofit organizations, public

HB3758 - 90 - LRB104 12225 JDS 22331 b
entities, or community members; and
(5) whether a project is developed in response
to a site-specific RFP developed by community
members or a nonprofit organization or public
entity located in or serving the community.
Selection criteria may also prioritize projects
that:
(1) are developed in collaboration with or to
provide complementary opportunities for the Clean
Jobs Workforce Network Program, the Illinois
Climate Works Preapprenticeship Program, the
Returning Residents Clean Jobs Training Program,
the Clean Energy Contractor Incubator Program, or
the Clean Energy Primes Contractor Accelerator
Program;
(2) increase the diversity of locations of
community solar projects in Illinois, including by
locating in urban areas and population centers;
(3) are located in Equity Investment Eligible
Communities;
(4) are not greenfield projects;
(5) serve only local subscribers;
(6) have a nameplate capacity that does not
exceed 500 kW;
(7) are developed by an equity eligible
contractor; or

HB3758 - 91 - LRB104 12225 JDS 22331 b
(8) otherwise meaningfully advance the goals
of providing more direct and tangible connection
and benefits to the communities which they serve
or in which they operate and increasing the
variety of community solar locations, models, and
options in Illinois.
For the purposes of this item (v):
"Community" means a social unit in which people
come together regularly to effect change; a social
unit in which participants are marked by a cooperative
spirit, a common purpose, or shared interests or
characteristics; or a space understood by its
residents to be delineated through geographic
boundaries or landmarks.
"Community benefit" means a range of services and
activities that provide affirmative, economic,
environmental, social, cultural, or physical value to
a community; or a mechanism that enables economic
development, high-quality employment, and education
opportunities for local workers and residents, or
formal monitoring and oversight structures such that
community members may ensure that those services and
activities respond to local knowledge and needs.
"Community ownership" means an arrangement in
which an electric generating facility is, or over time
will be, in significant part, owned collectively by

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members of the community to which an electric
generating facility provides benefits; members of that
community participate in decisions regarding the
governance, operation, maintenance, and upgrades of
and to that facility; and members of that community
benefit from regular use of that facility.
Terms and guidance within these criteria that are
not defined in this item (v) shall be defined by the
Agency, with stakeholder input, during the development
of the Agency's long-term renewable resources
procurement plan. The Agency shall develop regular
opportunities for projects to submit applications for
projects under this category, and develop selection
criteria that gives preference to projects that better
meet individual criteria as well as projects that
address a higher number of criteria.
(vi) At least 10% from distributed renewable
energy generation devices, which includes distributed
renewable energy devices with a nameplate capacity
under 5,000 kilowatts or photovoltaic community
renewable generation projects, from applicants that
are both approved vendors and equity eligible
contractors. The Agency may create subcategories
within this category to account for the differences
between project size and type. The Agency shall
propose to increase the percentage in this item (vi)

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over time to 40% based on factors, including, but not
limited to, the number of equity eligible contractors
and capacity used in this item (vi) in previous
delivery years.
The Agency shall propose a payment structure for
contracts executed pursuant to this paragraph under
which, upon a demonstration of qualification or need,
applicant firms are advanced capital disbursed after
contract execution but before the contracted project's
energization. The amount or percentage of capital
advanced prior to project energization shall be
sufficient to both cover any increase in development
costs resulting from prevailing wage requirements or
project-labor agreements, and designed to overcome
barriers in access to capital faced by equity eligible
contractors. The amount or percentage of advanced
capital may vary by subcategory within this category
and by an applicant's demonstration of need, with such
levels to be established through the Long-Term
Renewable Resources Procurement Plan authorized under
subparagraph (A) of paragraph (1) of subsection (c) of
this Section.
Contracts developed featuring capital advanced
prior to a project's energization shall feature
provisions to ensure both the successful development
of applicant projects and the delivery of the

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renewable energy credits for the full term of the
contract, including ongoing collateral requirements
and other provisions deemed necessary by the Agency,
and may include energization timelines longer than for
comparable project types. The percentage or amount of
capital advanced prior to project energization shall
not operate to increase the overall contract value,
however contracts executed under this subparagraph may
feature renewable energy credit prices higher than
those offered to similar projects participating in
other categories. Capital advanced prior to
energization shall serve to reduce the ratable
payments made after energization under items (ii) and
(iii) of subparagraph (L) or payments made for each
renewable energy credit delivery under item (iv) of
subparagraph (L).
(vii) The remaining capacity shall be allocated by
the Agency in order to respond to market demand. The
Agency shall allocate any discretionary capacity prior
to the beginning of each delivery year.
(viii) Notwithstanding the preceding, not more than 90
days after the effective date of this amendatory Act of
the 104th General Assembly, the Agency shall petition the
Commission to modify its Long-Term Renewable Resources
Procurement Plan as follows:
(1) the petition shall include an estimate of

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the size of blocks authorized under subparagraph
(i) of this paragraph (K) through the delivery
year beginning in 2030;
(2) the petition shall propose blocks for each
delivery year through the delivery year beginning
in 2030 and a floating block. The floating block
shall be equal to 35% of the total capacity the
blocks identified in the preceding sentence. To
the extent that capacity allocated to systems
described in subparagraph (i) of this paragraph is
exhausted before the end of the delivery year, the
Agency shall open the floating block or a portion
thereof in the discretion of the Agency until at
latest the commencement of the next delivery year.
The Agency may propose a price for the floating
block that is different from the annual block for
a given delivery year; and
(3) the petition shall propose a methodology
for reallocated capacity under the terms of the
Agency's Long-Term Renewable Resources Procurement
Plan. The Commission shall approve the Agency's
petition within 120 days after receiving the
petition, with any modifications that the
Commission finds are necessary to deploy
distributed renewable energy generation devices to
meet customer demand and enable the photovoltaic

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market to scale up and for renewable energy credit
prices to adjust at a predictable rate over time.
To the extent there is uncontracted capacity from any
block in any of categories (i) through (vi) at the end of a
delivery year, the Agency shall redistribute that capacity
to one or more other categories giving priority to
categories with projects on a waitlist. The redistributed
capacity shall be added to the annual capacity in the
subsequent delivery year, and the price for renewable
energy credits shall be the price for the new delivery
year. Redistributed capacity shall not be considered
redistributed when determining whether the goals in this
subsection (K) have been met.
Notwithstanding anything to the contrary, as the
Agency increases the capacity in item (vi) to 40% over
time, the Agency may reduce the capacity of items (i)
through (v) proportionate to the capacity of the
categories of projects in item (vi), to achieve a balance
of project types.
The Adjustable Block program shall be designed to
ensure that renewable energy credits are procured from
projects in diverse locations and are not concentrated in
a few regional areas.
(L) Notwithstanding provisions for advancing capital
prior to project energization found in item (vi) of
subparagraph (K), the procurement of photovoltaic

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renewable energy credits under items (i) through (vi) of
subparagraph (K) of this paragraph (1) shall otherwise be
subject to the following contract and payment terms:
(i) (Blank).
(i-3) Upon delivery of evidence of an increase of
over 100% of non-binding cost estimates for
interconnection from a study or interconnection
agreement issued prior to application of a system to
the program described in subparagraph (K) of this
paragraph (1) to a study or interconnection agreement
issued after such application, the approved vendor
submitting such application shall be entitled to
return of 100% of any performance assurance posted for
such system under a contract described in this
subparagraph (L).
(i-5) The Agency or its program administrator
shall complete the review of the materials as the
Agency may require to be submitted to trigger the
initial payment for a participating system under the
renewable energy credit contract no later than 6 weeks
after the completed submission.
(ii) For those renewable energy credits that
qualify and are procured under item (i) of
subparagraph (K) of this paragraph (1), and any
similar category projects that are procured under item
(vi) of subparagraph (K) of this paragraph (1) that

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qualify and are procured under item (vi), the contract
length shall be 15 years. The renewable energy credit
delivery contract value shall be paid in full, based
on the estimated generation during the first 15 years
of operation, by the contracting utilities at the time
that the facility producing the renewable energy
credits is interconnected at the distribution system
level of the utility and verified as energized and
compliant by the Program Administrator. The electric
utility shall receive and retire all renewable energy
credits generated by the project for the first 15
years of operation. Renewable energy credits generated
by the project thereafter shall not be transferred
under the renewable energy credit delivery contract
with the counterparty electric utility.
(iii) For those renewable energy credits that
qualify and are procured under item (ii) and (v) of
subparagraph (K) of this paragraph (1) and any like
projects similar category that qualify and are
procured under item (vi), the contract length shall be
15 years. 15% of the renewable energy credit delivery
contract value, based on the estimated generation
during the first 15 years of operation, shall be paid
by the contracting utilities at the time that the
facility producing the renewable energy credits is
interconnected at the distribution system level of the

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utility and verified as energized and compliant by the
Program Administrator. The remaining portion shall be
paid ratably over the subsequent 6-year period. The
electric utility shall receive and retire all
renewable energy credits generated by the project for
the first 15 years of operation. Renewable energy
credits generated by the project thereafter shall not
be transferred under the renewable energy credit
delivery contract with the counterparty electric
utility.
(iv) For those renewable energy credits that
qualify and are procured under items (iii) and (iv) of
subparagraph (K) of this paragraph (1), and any like
projects that qualify and are procured under item
(vi), the renewable energy credit delivery contract
length shall be 20 years and shall be paid over the
delivery term, not to exceed during each delivery year
the contract price multiplied by the estimated annual
renewable energy credit generation amount. If
generation of renewable energy credits during a
delivery year exceeds the estimated annual generation
amount, the excess renewable energy credits shall be
carried forward to future delivery years and shall not
expire during the delivery term. If generation of
renewable energy credits during a delivery year,
including carried forward excess renewable energy

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credits, if any, is less than the estimated annual
generation amount, payments during such delivery year
will not exceed the quantity generated plus the
quantity carried forward multiplied by the contract
price. The electric utility shall receive all
renewable energy credits generated by the project
during the first 20 years of operation and retire all
renewable energy credits paid for under this item (iv)
and return at the end of the delivery term all
renewable energy credits that were not paid for.
Renewable energy credits generated by the project
thereafter shall not be transferred under the
renewable energy credit delivery contract with the
counterparty electric utility. Notwithstanding the
preceding, for those projects participating under item
(iii) of subparagraph (K), the contract price for a
delivery year shall be based on subscription levels as
measured on the higher of the first business day of the
delivery year or the first business day 6 months after
the first business day of the delivery year.
Subscription of 90% of nameplate capacity or greater
shall be deemed to be fully subscribed for the
purposes of this item (iv). For projects receiving a
20-year delivery contract, REC prices shall be
adjusted downward for consistency with the incentive
levels previously determined to be necessary to

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support projects under 15-year delivery contracts,
taking into consideration any additional new
requirements placed on the projects, including, but
not limited to, labor standards.
(v) Each contract shall include provisions to
ensure the delivery of the estimated quantity of
renewable energy credits and ongoing collateral
requirements and other provisions deemed appropriate
by the Agency.
(vi) The utility shall be the counterparty to the
contracts executed under this subparagraph (L) that
are approved by the Commission under the process
described in Section 16-111.5 of the Public Utilities
Act. No contract shall be executed for an amount that
is less than one renewable energy credit per year.
(vii) If, at any time, approved applications for
the Adjustable Block program exceed funds collected by
the electric utility or would cause the Agency to
exceed the limitation described in subparagraph (E) of
this paragraph (1) on the amount of renewable energy
resources that may be procured, then the Agency may
consider future uncommitted funds to be reserved for
these contracts on a first-come, first-served basis.
(viii) Nothing in this Section shall require the
utility to advance any payment or pay any amounts that
exceed the actual amount of revenues anticipated to be

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collected by the utility under paragraph (6) of this
subsection (c) and subsection (k) of Section 16-108 of
the Public Utilities Act inclusive of eligible funds
collected in prior years and alternative compliance
payments for use by the utility, and contracts
executed under this Section shall expressly
incorporate this limitation.
(ix) Notwithstanding other requirements of this
subparagraph (L), no modification shall be required to
Adjustable Block program contracts if they were
already executed prior to the establishment, approval,
and implementation of new contract forms as a result
of this amendatory Act of the 102nd General Assembly.
(x) Contracts may be assignable, but only to
entities first deemed by the Agency to have met
program terms and requirements applicable to direct
program participation. In developing contracts for the
delivery of renewable energy credits, the Agency shall
be permitted to establish fees applicable to each
contract assignment.
(M) The Agency shall be authorized to retain one or
more experts or expert consulting firms to develop,
administer, implement, operate, and evaluate the
Adjustable Block program described in subparagraph (K) of
this paragraph (1), and the Agency shall retain the
consultant or consultants in the same manner, to the

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extent practicable, as the Agency retains others to
administer provisions of this Act, including, but not
limited to, the procurement administrator. The selection
of experts and expert consulting firms and the procurement
process described in this subparagraph (M) are exempt from
the requirements of Section 20-10 of the Illinois
Procurement Code, under Section 20-10 of that Code. The
Agency shall strive to minimize administrative expenses in
the implementation of the Adjustable Block program.
The Program Administrator may charge application fees
to participating firms to cover the cost of program
administration. Any application fee amounts shall
initially be determined through the long-term renewable
resources procurement plan, and modifications to any
application fee that deviate more than 25% from the
Commission's approved value must be approved by the
Commission as a long-term plan revision under Section
16-111.5 of the Public Utilities Act. The Agency shall
consider stakeholder feedback when making adjustments to
application fees and shall notify stakeholders in advance
of any planned changes.
In addition to covering the costs of program
administration, the Agency, in conjunction with its
Program Administrator, may also use the proceeds of such
fees charged to participating firms to support public
education and ongoing regional and national coordination

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with nonprofit organizations, public bodies, and others
engaged in the implementation of renewable energy
incentive programs or similar initiatives. This work may
include developing papers and reports, hosting regional
and national conferences, and other work deemed necessary
by the Agency to position the State of Illinois as a
national leader in renewable energy incentive program
development and administration.
The Agency and its consultant or consultants shall
monitor block activity, share program activity with
stakeholders and conduct quarterly meetings to discuss
program activity and market conditions. If necessary, the
Agency may make prospective administrative adjustments to
the Adjustable Block program design, such as making
adjustments to purchase prices as necessary to achieve the
goals of this subsection (c). Program modifications to any
block price that do not deviate from the Commission's
approved value by more than 10% shall take effect
immediately and are not subject to Commission review and
approval. Program modifications to any block price that
deviate more than 10% from the Commission's approved value
must be approved by the Commission as a long-term plan
amendment under Section 16-111.5 of the Public Utilities
Act. The Agency shall consider stakeholder feedback when
making adjustments to the Adjustable Block design and
shall notify stakeholders in advance of any planned

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changes.
The Agency and its program administrators for both the
Adjustable Block program and the Illinois Solar for All
Program, consistent with the requirements of this
subsection (c) and subsection (b) of Section 1-56 of this
Act, shall propose the Adjustable Block program terms,
conditions, and requirements, including the prices to be
paid for renewable energy credits, where applicable, and
requirements applicable to participating entities and
project applications, through the development, review, and
approval of the Agency's long-term renewable resources
procurement plan described in this subsection (c) and
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. Terms, conditions, and requirements
for program participation shall include the following:
(i) The Agency shall establish a registration
process for entities seeking to qualify for
program-administered incentive funding and establish
baseline qualifications for vendor approval. The
Agency must maintain a list of approved entities on
each program's website, and may revoke a vendor's
ability to receive program-administered incentive
funding status upon a determination that the vendor
failed to comply with contract terms, the law, or
other program requirements.
(ii) The Agency shall establish program

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requirements and minimum contract terms to ensure
projects are properly installed and produce their
expected amounts of energy. Program requirements may
include on-site inspections and photo documentation of
projects under construction. The Agency may require
repairs, alterations, or additions to remedy any
material deficiencies discovered. Vendors who have a
disproportionately high number of deficient systems
may lose their eligibility to continue to receive
State-administered incentive funding through Agency
programs and procurements.
(iii) To discourage deceptive marketing or other
bad faith business practices, the Agency may require
direct program participants, including agents
operating on their behalf, to provide standardized
disclosures to a customer prior to that customer's
execution of a contract for the development of a
distributed generation system or a subscription to a
community solar project.
(iv) The Agency shall establish one or multiple
Consumer Complaints Centers to accept complaints
regarding businesses that participate in, or otherwise
benefit from, State-administered incentive funding
through Agency-administered programs. The Agency shall
maintain a public database of complaints with any
confidential or particularly sensitive information

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redacted from public entries.
(v) Through a filing in the proceeding for the
approval of its long-term renewable energy resources
procurement plan, the Agency shall provide an annual
written report to the Illinois Commerce Commission
documenting the frequency and nature of complaints and
any enforcement actions taken in response to those
complaints.
(vi) The Agency shall schedule regular meetings
with representatives of the Office of the Attorney
General, the Illinois Commerce Commission, consumer
protection groups, and other interested stakeholders
to share relevant information about consumer
protection, project compliance, and complaints
received.
(vii) To the extent that complaints received
implicate the jurisdiction of the Office of the
Attorney General, the Illinois Commerce Commission, or
local, State, or federal law enforcement, the Agency
shall also refer complaints to those entities as
appropriate.
(N) The Agency shall establish the terms, conditions,
and program requirements for photovoltaic community
renewable generation projects with a goal to expand access
to a broader group of energy consumers, to ensure robust
participation opportunities for residential and small

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commercial customers and those who cannot install
renewable energy on their own properties. Subject to
reasonable limitations, any plan approved by the
Commission shall allow subscriptions to community
renewable generation projects to be portable and
transferable. For purposes of this subparagraph (N),
"portable" means that subscriptions may be retained by the
subscriber even if the subscriber relocates or changes its
address within the same utility service territory; and
"transferable" means that a subscriber may assign or sell
subscriptions to another person within the same utility
service territory.
Through the development of its long-term renewable
resources procurement plan, the Agency may consider
whether community renewable generation projects utilizing
technologies other than photovoltaics should be supported
through State-administered incentive funding, and may
issue requests for information to gauge market demand.
Electric utilities shall provide a monetary credit to
a subscriber's subsequent bill for service for the
proportional output of a community renewable generation
project attributable to that subscriber as specified in
Section 16-107.5 of the Public Utilities Act.
The Agency shall purchase renewable energy credits
from subscribed shares of photovoltaic community renewable
generation projects through the Adjustable Block program

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described in subparagraph (K) of this paragraph (1) or
through the Illinois Solar for All Program described in
Section 1-56 of this Act. The electric utility shall
purchase any unsubscribed energy from community renewable
generation projects that are Qualifying Facilities ("QF")
under the electric utility's tariff for purchasing the
output from QFs under Public Utilities Regulatory Policies
Act of 1978.
The owners of and any subscribers to a community
renewable generation project shall not be considered
public utilities or alternative retail electricity
suppliers under the Public Utilities Act solely as a
result of their interest in or subscription to a community
renewable generation project and shall not be required to
become an alternative retail electric supplier by
participating in a community renewable generation project
with a public utility.
(O) For the delivery year beginning June 1, 2018, the
long-term renewable resources procurement plan required by
this subsection (c) shall provide for the Agency to
procure contracts to continue offering the Illinois Solar
for All Program described in subsection (b) of Section
1-56 of this Act, and the contracts approved by the
Commission shall be executed by the utilities that are
subject to this subsection (c). The long-term renewable
resources procurement plan shall allocate up to

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

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administered under this Act, and small businesses.
The Agency shall develop a method to optimize
procurement of renewable energy credits from proposed
utility-scale projects that are located in communities
eligible to receive Energy Transition Community Grants
pursuant to Section 10-20 of the Energy Community
Reinvestment Act. If this requirement conflicts with other
provisions of law or the Agency determines that full
compliance with the requirements of this subparagraph (P)
would be unreasonably costly or administratively
impractical, the Agency is to propose alternative
approaches to achieve development of renewable energy
resources in communities eligible to receive Energy
Transition Community Grants pursuant to Section 10-20 of
the Energy Community Reinvestment Act or seek an exemption
from this requirement from the Commission.
(Q) Each facility listed in subitems (i) through (ix)
of item (1) of this subparagraph (Q) for which a renewable
energy credit delivery contract is signed after the
effective date of this amendatory Act of the 102nd General
Assembly is subject to the following requirements through
the Agency's long-term renewable resources procurement
plan:
(1) Each facility shall be subject to the
prevailing wage requirements included in the
Prevailing Wage Act. The Agency shall require

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verification that all construction performed on the
facility by the renewable energy credit delivery
contract holder, its contractors, or its
subcontractors relating to construction of the
facility is performed by construction employees
receiving an amount for that work equal to or greater
than the general prevailing rate, as that term is
defined in Section 3 of the Prevailing Wage Act. For
purposes of this item (1), "house of worship" means
property that is both (1) used exclusively by a
religious society or body of persons as a place for
religious exercise or religious worship and (2)
recognized as exempt from taxation pursuant to Section
15-40 of the Property Tax Code. This item (1) shall
apply to any the following:
(i) all new utility-scale wind projects;
(ii) all new utility-scale photovoltaic
projects;
(iii) all new brownfield photovoltaic
projects;
(iv) all new photovoltaic community renewable
energy facilities and any associated energy
storage systems that qualify for item (iii) of
subparagraph (K) of this paragraph (1);
(v) all new community driven community
photovoltaic projects and any associated energy

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storage systems that qualify for item (v) of
subparagraph (K) of this paragraph (1);
(vi) all new photovoltaic projects on public
school land that qualify for item (iv) of
subparagraph (K) of this paragraph (1);
(vii) all new photovoltaic distributed
renewable energy generation devices and any
associated energy storage systems that (1) qualify
for item (i) of subparagraph (K) of this paragraph
(1); (2) are not projects that serve single-family
or multi-family residential buildings; and (3) are
not houses of worship where the aggregate capacity
including collocated projects would not exceed 100
kilowatts;
(viii) all new photovoltaic distributed
renewable energy generation devices and any
associated energy storage systems that (1) qualify
for item (ii) of subparagraph (K) of this
paragraph (1); (2) are not projects that serve
single-family or multi-family residential
buildings; and (3) are not houses of worship where
the aggregate capacity including collocated
projects would not exceed 100 kilowatts;
(ix) all new, modernized, or retooled
hydropower facilities.
(2) Renewable energy credits procured from new

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utility-scale wind projects, new utility-scale solar
projects, and new brownfield solar projects pursuant
to Agency procurement events occurring after the
effective date of this amendatory Act of the 102nd
General Assembly must be from facilities built by
general contractors that must enter into a project
labor agreement, as defined by this Act, prior to
construction. The project labor agreement shall be
filed with the Director in accordance with procedures
established by the Agency through its long-term
renewable resources procurement plan. Any information
submitted to the Agency in this item (2) shall be
considered commercially sensitive information. At a
minimum, the project labor agreement must provide the
names, addresses, and occupations of the owner of the
plant and the individuals representing the labor
organization employees participating in the project
labor agreement consistent with the Project Labor
Agreements Act. The agreement must also specify the
terms and conditions as defined by this Act.
(3) It is the intent of this Section to ensure that
economic development occurs across Illinois
communities, that emerging businesses may grow, and
that there is improved access to the clean energy
economy by persons who have greater economic burdens
to success. The Agency shall take into consideration

HB3758 - 115 - LRB104 12225 JDS 22331 b
the unique cost of compliance of this subparagraph (Q)
that might be borne by equity eligible contractors,
shall include such costs when determining the price of
renewable energy credits in the Adjustable Block
program, and shall take such costs into consideration
in a nondiscriminatory manner when comparing bids for
competitive procurements. The Agency shall consider
costs associated with compliance whether in the
development, financing, or construction of projects.
The Agency shall periodically review the assumptions
in these costs and may adjust prices, in compliance
with subparagraph (M) of this paragraph (1).
(R) In its long-term renewable resources procurement
plan, the Agency shall establish a self-direct renewable
portfolio standard compliance program for eligible
self-direct customers that purchase renewable energy
credits from utility-scale wind and solar projects through
long-term agreements for purchase of renewable energy
credits as described in this Section. Such long-term
agreements may include the purchase of energy or other
products on a physical or financial basis and may involve
an alternative retail electric supplier as defined in
Section 16-102 of the Public Utilities Act. This program
shall take effect in the delivery year commencing June 1,
2023.
(1) For the purposes of this subparagraph:

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"Eligible self-direct customer" means any retail
customers of an electric utility that serves 3,000,000
or more retail customers in the State and whose total
highest 30-minute demand was more than 10,000
kilowatts, or any retail customers of an electric
utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in
the State and whose total highest 15-minute demand was
more than 10,000 kilowatts.
"Retail customer" has the meaning set forth in
Section 16-102 of the Public Utilities Act and
multiple retail customer accounts under the same
corporate parent may aggregate their account demands
to meet the 10,000 kilowatt threshold. The criteria
for determining whether this subparagraph is
applicable to a retail customer shall be based on the
12 consecutive billing periods prior to the start of
the year in which the application is filed.
(2) For renewable energy credits to count toward
the self-direct renewable portfolio standard
compliance program, they must:
(i) qualify as renewable energy credits as
defined in Section 1-10 of this Act;
(ii) be sourced from one or more renewable
energy generating facilities that comply with the
geographic requirements as set forth in

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subparagraph (I) of paragraph (1) of subsection
(c) as interpreted through the Agency's long-term
renewable resources procurement plan, or, where
applicable, the geographic requirements that
governed utility-scale renewable energy credits at
the time the eligible self-direct customer entered
into the applicable renewable energy credit
purchase agreement;
(iii) be procured through long-term contracts
with term lengths of at least 10 years either
directly with the renewable energy generating
facility or through a bundled power purchase
agreement, a virtual power purchase agreement, an
agreement between the renewable generating
facility, an alternative retail electric supplier,
and the customer, or such other structure as is
permissible under this subparagraph (R);
(iv) be equivalent in volume to at least 40%
of the eligible self-direct customer's usage,
determined annually by the eligible self-direct
customer's usage during the previous delivery
year, measured to the nearest megawatt-hour;
(v) be retired by or on behalf of the large
energy customer;
(vi) be sourced from new utility-scale wind
projects or new utility-scale solar projects; and

HB3758 - 118 - LRB104 12225 JDS 22331 b
(vii) if the contracts for renewable energy
credits are entered into after the effective date
of this amendatory Act of the 102nd General
Assembly, the new utility-scale wind projects or
new utility-scale solar projects must comply with
the requirements established in subparagraphs (P)
and (Q) of paragraph (1) of this subsection (c)
and subsection (c-10).
(3) The self-direct renewable portfolio standard
compliance program shall be designed to allow eligible
self-direct customers to procure new renewable energy
credits from new utility-scale wind projects or new
utility-scale photovoltaic projects. The Agency shall
annually determine the amount of utility-scale
renewable energy credits it will include each year
from the self-direct renewable portfolio standard
compliance program, subject to receiving qualifying
applications. In making this determination, the Agency
shall evaluate publicly available analyses and studies
of the potential market size for utility-scale
renewable energy long-term purchase agreements by
commercial and industrial energy customers and make
that report publicly available. If demand for
participation in the self-direct renewable portfolio
standard compliance program exceeds availability, the
Agency shall ensure participation is evenly split

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between commercial and industrial users to the extent
there is sufficient demand from both customer classes.
Each renewable energy credit procured pursuant to this
subparagraph (R) by a self-direct customer shall
reduce the total volume of renewable energy credits
the Agency is otherwise required to procure from new
utility-scale projects pursuant to subparagraph (C) of
paragraph (1) of this subsection (c) on behalf of
contracting utilities where the eligible self-direct
customer is located. The self-direct customer shall
file an annual compliance report with the Agency
pursuant to terms established by the Agency through
its long-term renewable resources procurement plan to
be eligible for participation in this program.
Customers must provide the Agency with their most
recent electricity billing statements or other
information deemed necessary by the Agency to
demonstrate they are an eligible self-direct customer.
(4) The Commission shall approve a reduction in
the volumetric charges collected pursuant to Section
16-108 of the Public Utilities Act for approved
eligible self-direct customers equivalent to the
anticipated cost of renewable energy credit deliveries
under contracts for new utility-scale wind and new
utility-scale solar entered for each delivery year
after the large energy customer begins retiring

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eligible new utility scale renewable energy credits
for self-compliance. The self-direct credit amount
shall be determined annually and is equal to the
estimated portion of the cost authorized by
subparagraph (E) of paragraph (1) of this subsection
(c) that supported the annual procurement of
utility-scale renewable energy credits in the prior
delivery year using a methodology described in the
long-term renewable resources procurement plan,
expressed on a per kilowatthour basis, and does not
include (i) costs associated with any contracts
entered into before the delivery year in which the
customer files the initial compliance report to be
eligible for participation in the self-direct program,
and (ii) costs associated with procuring renewable
energy credits through existing and future contracts
through the Adjustable Block Program, subsection (c-5)
of this Section 1-75, and the Solar for All Program.
The Agency shall assist the Commission in determining
the current and future costs. The Agency must
determine the self-direct credit amount for new and
existing eligible self-direct customers and submit
this to the Commission in an annual compliance filing.
The Commission must approve the self-direct credit
amount by June 1, 2023 and June 1 of each delivery year
thereafter.

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(5) Customers described in this subparagraph (R)
shall apply, on a form developed by the Agency, to the
Agency to be designated as a self-direct eligible
customer. Once the Agency determines that a
self-direct customer is eligible for participation in
the program, the self-direct customer will remain
eligible until the end of the term of the contract.
Thereafter, application may be made not less than 12
months before the filing date of the long-term
renewable resources procurement plan described in this
Act. At a minimum, such application shall contain the
following:
(i) the customer's certification that, at the
time of the customer's application, the customer
qualifies to be a self-direct eligible customer,
including documents demonstrating that
qualification;
(ii) the customer's certification that the
customer has entered into or will enter into by
the beginning of the applicable procurement year,
one or more bilateral contracts for new wind
projects or new photovoltaic projects, including
supporting documentation;
(iii) certification that the contract or
contracts for new renewable energy resources are
long-term contracts with term lengths of at least

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10 years, including supporting documentation;
(iv) certification of the quantities of
renewable energy credits that the customer will
purchase each year under such contract or
contracts, including supporting documentation;
(v) proof that the contract is sufficient to
produce renewable energy credits to be equivalent
in volume to at least 40% of the large energy
customer's usage from the previous delivery year,
measured to the nearest megawatt-hour; and
(vi) certification that the customer intends
to maintain the contract for the duration of the
length of the contract.
(6) If a customer receives the self-direct credit
but fails to properly procure and retire renewable
energy credits as required under this subparagraph
(R), the Commission, on petition from the Agency and
after notice and hearing, may direct such customer's
utility to recover the cost of the wrongfully received
self-direct credits plus interest through an adder to
charges assessed pursuant to Section 16-108 of the
Public Utilities Act. Self-direct customers who
knowingly fail to properly procure and retire
renewable energy credits and do not notify the Agency
are ineligible for continued participation in the
self-direct renewable portfolio standard compliance

HB3758 - 123 - LRB104 12225 JDS 22331 b
program.
(2) (Blank).
(3) (Blank).
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the 2010 delivery year and ending
June 1, 2017, an electric utility subject to this
subsection (c) shall apply the lesser of the maximum
alternative compliance payment rate or the most recent
estimated alternative compliance payment rate for its
service territory for the corresponding compliance period,
established pursuant to subsection (d) of Section 16-115D
of the Public Utilities Act to its retail customers that
take service pursuant to the electric utility's hourly
pricing tariff or tariffs. The electric utility shall
retain all amounts collected as a result of the
application of the alternative compliance payment rate or
rates to such customers, and, beginning in 2011, the
utility shall include in the information provided under
item (1) of subsection (d) of Section 16-111.5 of the
Public Utilities Act the amounts collected under the
alternative compliance payment rate or rates for the prior
year ending May 31. Notwithstanding any limitation on the
procurement of renewable energy resources imposed by item
(2) of this subsection (c), the Agency shall increase its
spending on the purchase of renewable energy resources to

HB3758 - 124 - LRB104 12225 JDS 22331 b
be procured by the electric utility for the next plan year
by an amount equal to the amounts collected by the utility
under the alternative compliance payment rate or rates in
the prior year ending May 31.
(6) The electric utility shall be entitled to recover
all of its costs associated with the procurement of
renewable energy credits under plans approved under this
Section and Section 16-111.5 of the Public Utilities Act.
These costs shall include associated reasonable expenses
for implementing the procurement programs, including, but
not limited to, the costs of administering and evaluating
the Adjustable Block program, through an automatic
adjustment clause tariff in accordance with subsection (k)
of Section 16-108 of the Public Utilities Act.
(7) Renewable energy credits procured from new
photovoltaic projects or new distributed renewable energy
generation devices under this Section after June 1, 2017
(the effective date of Public Act 99-906) must be procured
from devices installed by a qualified person in compliance
with the requirements of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder.
In meeting the renewable energy requirements of this
subsection (c), to the extent feasible and consistent with
State and federal law, the renewable energy credit
procurements, Adjustable Block solar program, and

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community renewable generation program shall provide
employment opportunities for all segments of the
population and workforce, including minority-owned and
female-owned business enterprises, and shall not,
consistent with State and federal law, discriminate based
on race or socioeconomic status.
(c-5) Procurement of renewable energy credits from new
renewable energy facilities installed at or adjacent to the
sites of electric generating facilities that burn or burned
coal as their primary fuel source.
(1) In addition to the procurement of renewable energy
credits pursuant to long-term renewable resources
procurement plans in accordance with subsection (c) of
this Section and Section 16-111.5 of the Public Utilities
Act, the Agency shall conduct procurement events in
accordance with this subsection (c-5) for the procurement
by electric utilities that served more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new renewable energy facilities to be
installed at or adjacent to the sites of electric
generating facilities that, as of January 1, 2016, burned
coal as their primary fuel source and meet the other
criteria specified in this subsection (c-5). For purposes
of this subsection (c-5), "new renewable energy facility"
means a new utility-scale solar project as defined in this
Section 1-75. The renewable energy credits procured

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pursuant to this subsection (c-5) may be included or
counted for purposes of compliance with the amounts of
renewable energy credits required to be procured pursuant
to subsection (c) of this Section to the extent that there
are otherwise shortfalls in compliance with such
requirements. The procurement of renewable energy credits
by electric utilities pursuant to this subsection (c-5)
shall be funded solely by revenues collected from the Coal
to Solar and Energy Storage Initiative Charge provided for
in this subsection (c-5) and subsection (i-5) of Section
16-108 of the Public Utilities Act, shall not be funded by
revenues collected through any of the other funding
mechanisms provided for in subsection (c) of this Section,
and shall not be subject to the limitation imposed by
subsection (c) on charges to retail customers for costs to
procure renewable energy resources pursuant to subsection
(c), and shall not be subject to any other requirements or
limitations of subsection (c).
(2) The Agency shall conduct 2 procurement events to
select owners of electric generating facilities meeting
the eligibility criteria specified in this subsection
(c-5) to enter into long-term contracts to sell renewable
energy credits to electric utilities serving more than
300,000 retail customers in this State as of January 1,
2019. The first procurement event shall be conducted no
later than March 31, 2022, unless the Agency elects to

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delay it, until no later than May 1, 2022, due to its
overall volume of work, and shall be to select owners of
electric generating facilities located in this State and
south of federal Interstate Highway 80 that meet the
eligibility criteria specified in this subsection (c-5).
The second procurement event shall be conducted no sooner
than September 30, 2022 and no later than October 31, 2022
and shall be to select owners of electric generating
facilities located anywhere in this State that meet the
eligibility criteria specified in this subsection (c-5).
The Agency shall establish and announce a time period,
which shall begin no later than 30 days prior to the
scheduled date for the procurement event, during which
applicants may submit applications to be selected as
suppliers of renewable energy credits pursuant to this
subsection (c-5). The eligibility criteria for selection
as a supplier of renewable energy credits pursuant to this
subsection (c-5) shall be as follows:
(A) The applicant owns an electric generating
facility located in this State that: (i) as of January
1, 2016, burned coal as its primary fuel to generate
electricity; and (ii) has, or had prior to retirement,
an electric generating capacity of at least 150
megawatts. The electric generating facility can be
either: (i) retired as of the date of the procurement
event; or (ii) still operating as of the date of the

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procurement event.
(B) The applicant is not (i) an electric
cooperative as defined in Section 3-119 of the Public
Utilities Act, or (ii) an entity described in
subsection (b)(1) of Section 3-105 of the Public
Utilities Act, or an association or consortium of or
an entity owned by entities described in (i) or (ii);
and the coal-fueled electric generating facility was
at one time owned, in whole or in part, by a public
utility as defined in Section 3-105 of the Public
Utilities Act.
(C) If participating in the first procurement
event, the applicant proposes and commits to construct
and operate, at the site, and if necessary for
sufficient space on property adjacent to the existing
property, at which the electric generating facility
identified in paragraph (A) is located: (i) a new
renewable energy facility of at least 20 megawatts but
no more than 100 megawatts of electric generating
capacity, and (ii) an energy storage facility having a
storage capacity equal to at least 2 megawatts and at
most 10 megawatts. If participating in the second
procurement event, the applicant proposes and commits
to construct and operate, at the site, and if
necessary for sufficient space on property adjacent to
the existing property, at which the electric

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generating facility identified in paragraph (A) is
located: (i) a new renewable energy facility of at
least 5 megawatts but no more than 20 megawatts of
electric generating capacity, and (ii) an energy
storage facility having a storage capacity equal to at
least 0.5 megawatts and at most one megawatt.
(D) The applicant agrees that the new renewable
energy facility and the energy storage facility will
be constructed or installed by a qualified entity or
entities in compliance with the requirements of
subsection (g) of Section 16-128A of the Public
Utilities Act and any rules adopted thereunder.
(E) The applicant agrees that personnel operating
the new renewable energy facility and the energy
storage facility will have the requisite skills,
knowledge, training, experience, and competence, which
may be demonstrated by completion or current
participation and ultimate completion by employees of
an accredited or otherwise recognized apprenticeship
program for the employee's particular craft, trade, or
skill, including through training and education
courses and opportunities offered by the owner to
employees of the coal-fueled electric generating
facility or by previous employment experience
performing the employee's particular work skill or
function.

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(F) The applicant commits that not less than the
prevailing wage, as determined pursuant to the
Prevailing Wage Act, will be paid to the applicant's
employees engaged in construction activities
associated with the new renewable energy facility and
the new energy storage facility and to the employees
of applicant's contractors engaged in construction
activities associated with the new renewable energy
facility and the new energy storage facility, and
that, on or before the commercial operation date of
the new renewable energy facility, the applicant shall
file a report with the Agency certifying that the
requirements of this subparagraph (F) have been met.
(G) The applicant commits that if selected, it
will negotiate a project labor agreement for the
construction of the new renewable energy facility and
associated energy storage facility that includes
provisions requiring the parties to the agreement to
work together to establish diversity threshold
requirements and to ensure best efforts to meet
diversity targets, improve diversity at the applicable
job site, create diverse apprenticeship opportunities,
and create opportunities to employ former coal-fired
power plant workers.
(H) The applicant commits to enter into a contract
or contracts for the applicable duration to provide

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specified numbers of renewable energy credits each
year from the new renewable energy facility to
electric utilities that served more than 300,000
retail customers in this State as of January 1, 2019,
at a price of $30 per renewable energy credit. The
price per renewable energy credit shall be fixed at
$30 for the applicable duration and the renewable
energy credits shall not be indexed renewable energy
credits as provided for in item (v) of subparagraph
(G) of paragraph (1) of subsection (c) of Section 1-75
of this Act. The applicable duration of each contract
shall be 20 years, unless the applicant is physically
interconnected to the PJM Interconnection, LLC
transmission grid and had a generating capacity of at
least 1,200 megawatts as of January 1, 2021, in which
case the applicable duration of the contract shall be
15 years.
(I) The applicant's application is certified by an
officer of the applicant and by an officer of the
applicant's ultimate parent company, if any.
(3) An applicant may submit applications to contract
to supply renewable energy credits from more than one new
renewable energy facility to be constructed at or adjacent
to one or more qualifying electric generating facilities
owned by the applicant. The Agency may select new
renewable energy facilities to be located at or adjacent

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to the sites of more than one qualifying electric
generation facility owned by an applicant to contract with
electric utilities to supply renewable energy credits from
such facilities.
(4) The Agency shall assess fees to each applicant to
recover the Agency's costs incurred in receiving and
evaluating applications, conducting the procurement event,
developing contracts for sale, delivery and purchase of
renewable energy credits, and monitoring the
administration of such contracts, as provided for in this
subsection (c-5), including fees paid to a procurement
administrator retained by the Agency for one or more of
these purposes.
(5) The Agency shall select the applicants and the new
renewable energy facilities to contract with electric
utilities to supply renewable energy credits in accordance
with this subsection (c-5). In the first procurement
event, the Agency shall select applicants and new
renewable energy facilities to supply renewable energy
credits, at a price of $30 per renewable energy credit,
aggregating to no less than 400,000 renewable energy
credits per year for the applicable duration, assuming
sufficient qualifying applications to supply, in the
aggregate, at least that amount of renewable energy
credits per year; and not more than 580,000 renewable
energy credits per year for the applicable duration. In

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the second procurement event, the Agency shall select
applicants and new renewable energy facilities to supply
renewable energy credits, at a price of $30 per renewable
energy credit, aggregating to no more than 625,000
renewable energy credits per year less the amount of
renewable energy credits each year contracted for as a
result of the first procurement event, for the applicable
durations. The number of renewable energy credits to be
procured as specified in this paragraph (5) shall not be
reduced based on renewable energy credits procured in the
self-direct renewable energy credit compliance program
established pursuant to subparagraph (R) of paragraph (1)
of subsection (c) of Section 1-75.
(6) The obligation to purchase renewable energy
credits from the applicants and their new renewable energy
facilities selected by the Agency shall be allocated to
the electric utilities based on their respective
percentages of kilowatthours delivered to delivery
services customers to the aggregate kilowatthour
deliveries by the electric utilities to delivery services
customers for the year ended December 31, 2021. In order
to achieve these allocation percentages between or among
the electric utilities, the Agency shall require each
applicant that is selected in the procurement event to
enter into a contract with each electric utility for the
sale and purchase of renewable energy credits from each

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new renewable energy facility to be constructed and
operated by the applicant, with the sale and purchase
obligations under the contracts to aggregate to the total
number of renewable energy credits per year to be supplied
by the applicant from the new renewable energy facility.
(7) The Agency shall submit its proposed selection of
applicants, new renewable energy facilities to be
constructed, and renewable energy credit amounts for each
procurement event to the Commission for approval. The
Commission shall, within 2 business days after receipt of
the Agency's proposed selections, approve the proposed
selections if it determines that the applicants and the
new renewable energy facilities to be constructed meet the
selection criteria set forth in this subsection (c-5) and
that the Agency seeks approval for contracts of applicable
durations aggregating to no more than the maximum amount
of renewable energy credits per year authorized by this
subsection (c-5) for the procurement event, at a price of
$30 per renewable energy credit.
(8) The Agency, in conjunction with its procurement
administrator if one is retained, the electric utilities,
and potential applicants for contracts to produce and
supply renewable energy credits pursuant to this
subsection (c-5), shall develop a standard form contract
for the sale, delivery and purchase of renewable energy
credits pursuant to this subsection (c-5). Each contract

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resulting from the first procurement event shall allow for
a commercial operation date for the new renewable energy
facility of either June 1, 2023 or June 1, 2024, with such
dates subject to adjustment as provided in this paragraph.
Each contract resulting from the second procurement event
shall provide for a commercial operation date on June 1
next occurring up to 48 months after execution of the
contract. Each contract shall provide that the owner shall
receive payments for renewable energy credits for the
applicable durations beginning with the commercial
operation date of the new renewable energy facility. The
form contract shall provide for adjustments to the
commercial operation and payment start dates as needed due
to any delays in completing the procurement and
contracting processes, in finalizing interconnection
agreements and installing interconnection facilities, and
in obtaining other necessary governmental permits and
approvals. The form contract shall be, to the maximum
extent possible, consistent with standard electric
industry contracts for sale, delivery, and purchase of
renewable energy credits while taking into account the
specific requirements of this subsection (c-5). The form
contract shall provide for over-delivery and
under-delivery of renewable energy credits within
reasonable ranges during each 12-month period and penalty,
default, and enforcement provisions for failure of the

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selling party to deliver renewable energy credits as
specified in the contract and to comply with the
requirements of this subsection (c-5). The standard form
contract shall specify that all renewable energy credits
delivered to the electric utility pursuant to the contract
shall be retired. The Agency shall make the proposed
contracts available for a reasonable period for comment by
potential applicants, and shall publish the final form
contract at least 30 days before the date of the first
procurement event.
(9) Coal to Solar and Energy Storage Initiative
Charge.
(A) By no later than July 1, 2022, each electric
utility that served more than 300,000 retail customers
in this State as of January 1, 2019 shall file a tariff
with the Commission for the billing and collection of
a Coal to Solar and Energy Storage Initiative Charge
in accordance with subsection (i-5) of Section 16-108
of the Public Utilities Act, with such tariff to be
effective, following review and approval or
modification by the Commission, beginning January 1,
2023. The tariff shall provide for the calculation and
setting of the electric utility's Coal to Solar and
Energy Storage Initiative Charge to collect revenues
estimated to be sufficient, in the aggregate, (i) to
enable the electric utility to pay for the renewable

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energy credits it has contracted to purchase in the
delivery year beginning June 1, 2023 and each delivery
year thereafter from new renewable energy facilities
located at the sites of qualifying electric generating
facilities, and (ii) to fund the grant payments to be
made in each delivery year by the Department of
Commerce and Economic Opportunity, or any successor
department or agency, which shall be referred to in
this subsection (c-5) as the Department, pursuant to
paragraph (10) of this subsection (c-5). The electric
utility's tariff shall provide for the billing and
collection of the Coal to Solar and Energy Storage
Initiative Charge on each kilowatthour of electricity
delivered to its delivery services customers within
its service territory and shall provide for an annual
reconciliation of revenues collected with actual
costs, in accordance with subsection (i-5) of Section
16-108 of the Public Utilities Act.
(B) Each electric utility shall remit on a monthly
basis to the State Treasurer, for deposit in the Coal
to Solar and Energy Storage Initiative Fund provided
for in this subsection (c-5), the electric utility's
collections of the Coal to Solar and Energy Storage
Initiative Charge in the amount estimated to be needed
by the Department for grant payments pursuant to grant
contracts entered into by the Department pursuant to

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paragraph (10) of this subsection (c-5).
(10) Coal to Solar and Energy Storage Initiative Fund.
(A) The Coal to Solar and Energy Storage
Initiative Fund is established as a special fund in
the State treasury. The Coal to Solar and Energy
Storage Initiative Fund is authorized to receive, by
statutory deposit, that portion specified in item (B)
of paragraph (9) of this subsection (c-5) of moneys
collected by electric utilities through imposition of
the Coal to Solar and Energy Storage Initiative Charge
required by this subsection (c-5). The Coal to Solar
and Energy Storage Initiative Fund shall be
administered by the Department to provide grants to
support the installation and operation of energy
storage facilities at the sites of qualifying electric
generating facilities meeting the criteria specified
in this paragraph (10).
(B) The Coal to Solar and Energy Storage
Initiative Fund shall not be subject to sweeps,
administrative charges, or chargebacks, including, but
not limited to, those authorized under Section 8h of
the State Finance Act, that would in any way result in
the transfer of those funds from the Coal to Solar and
Energy Storage Initiative Fund to any other fund of
this State or in having any such funds utilized for any
purpose other than the express purposes set forth in

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this paragraph (10).
(C) The Department shall utilize up to
$280,500,000 in the Coal to Solar and Energy Storage
Initiative Fund for grants, assuming sufficient
qualifying applicants, to support installation of
energy storage facilities at the sites of up to 3
qualifying electric generating facilities located in
the Midcontinent Independent System Operator, Inc.,
region in Illinois and the sites of up to 2 qualifying
electric generating facilities located in the PJM
Interconnection, LLC region in Illinois that meet the
criteria set forth in this subparagraph (C). The
criteria for receipt of a grant pursuant to this
subparagraph (C) are as follows:
(1) the electric generating facility at the
site has, or had prior to retirement, an electric
generating capacity of at least 150 megawatts;
(2) the electric generating facility burns (or
burned prior to retirement) coal as its primary
source of fuel;
(3) if the electric generating facility is
retired, it was retired subsequent to January 1,
2016;
(4) the owner of the electric generating
facility has not been selected by the Agency
pursuant to this subsection (c-5) of this Section

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to enter into a contract to sell renewable energy
credits to one or more electric utilities from a
new renewable energy facility located or to be
located at or adjacent to the site at which the
electric generating facility is located;
(5) the electric generating facility located
at the site was at one time owned, in whole or in
part, by a public utility as defined in Section
3-105 of the Public Utilities Act;
(6) the electric generating facility at the
site is not owned by (i) an electric cooperative
as defined in Section 3-119 of the Public
Utilities Act, or (ii) an entity described in
subsection (b)(1) of Section 3-105 of the Public
Utilities Act, or an association or consortium of
or an entity owned by entities described in items
(i) or (ii);
(7) the proposed energy storage facility at
the site will have energy storage capacity of at
least 37 megawatts;
(8) the owner commits to place the energy
storage facility into commercial operation on
either June 1, 2023, June 1, 2024, or June 1, 2025,
with such date subject to adjustment as needed due
to any delays in completing the grant contracting
process, in finalizing interconnection agreements

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and in installing interconnection facilities, and
in obtaining necessary governmental permits and
approvals;
(9) the owner agrees that the new energy
storage facility will be constructed or installed
by a qualified entity or entities consistent with
the requirements of subsection (g) of Section
16-128A of the Public Utilities Act and any rules
adopted under that Section;
(10) the owner agrees that personnel operating
the energy storage facility will have the
requisite skills, knowledge, training, experience,
and competence, which may be demonstrated by
completion or current participation and ultimate
completion by employees of an accredited or
otherwise recognized apprenticeship program for
the employee's particular craft, trade, or skill,
including through training and education courses
and opportunities offered by the owner to
employees of the coal-fueled electric generating
facility or by previous employment experience
performing the employee's particular work skill or
function;
(11) the owner commits that not less than the
prevailing wage, as determined pursuant to the
Prevailing Wage Act, will be paid to the owner's

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employees engaged in construction activities
associated with the new energy storage facility
and to the employees of the owner's contractors
engaged in construction activities associated with
the new energy storage facility, and that, on or
before the commercial operation date of the new
energy storage facility, the owner shall file a
report with the Department certifying that the
requirements of this subparagraph (11) have been
met; and
(12) the owner commits that if selected to
receive a grant, it will negotiate a project labor
agreement for the construction of the new energy
storage facility that includes provisions
requiring the parties to the agreement to work
together to establish diversity threshold
requirements and to ensure best efforts to meet
diversity targets, improve diversity at the
applicable job site, create diverse apprenticeship
opportunities, and create opportunities to employ
former coal-fired power plant workers.
The Department shall accept applications for this
grant program until March 31, 2022 and shall announce
the award of grants no later than June 1, 2022. The
Department shall make the grant payments to a
recipient in equal annual amounts for 10 years

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following the date the energy storage facility is
placed into commercial operation. The annual grant
payments to a qualifying energy storage facility shall
be $110,000 per megawatt of energy storage capacity,
with total annual grant payments pursuant to this
subparagraph (C) for qualifying energy storage
facilities not to exceed $28,050,000 in any year.
(D) Grants of funding for energy storage
facilities pursuant to subparagraph (C) of this
paragraph (10), from the Coal to Solar and Energy
Storage Initiative Fund, shall be memorialized in
grant contracts between the Department and the
recipient. The grant contracts shall specify the date
or dates in each year on which the annual grant
payments shall be paid.
(E) All disbursements from the Coal to Solar and
Energy Storage Initiative Fund shall be made only upon
warrants of the Comptroller drawn upon the Treasurer
as custodian of the Fund upon vouchers signed by the
Director of the Department or by the person or persons
designated by the Director of the Department for that
purpose. The Comptroller is authorized to draw the
warrants upon vouchers so signed. The Treasurer shall
accept all written warrants so signed and shall be
released from liability for all payments made on those
warrants.

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(11) Diversity, equity, and inclusion plans.
(A) Each applicant selected in a procurement event
to contract to supply renewable energy credits in
accordance with this subsection (c-5) and each owner
selected by the Department to receive a grant or
grants to support the construction and operation of a
new energy storage facility or facilities in
accordance with this subsection (c-5) shall, within 60
days following the Commission's approval of the
applicant to contract to supply renewable energy
credits or within 60 days following execution of a
grant contract with the Department, as applicable,
submit to the Commission a diversity, equity, and
inclusion plan setting forth the applicant's or
owner's numeric goals for the diversity composition of
its supplier entities for the new renewable energy
facility or new energy storage facility, as
applicable, which shall be referred to for purposes of
this paragraph (11) as the project, and the
applicant's or owner's action plan and schedule for
achieving those goals.
(B) For purposes of this paragraph (11), diversity
composition shall be based on the percentage, which
shall be a minimum of 25%, of eligible expenditures
for contract awards for materials and services (which
shall be defined in the plan) to business enterprises

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owned by minority persons, women, or persons with
disabilities as defined in Section 2 of the Business
Enterprise for Minorities, Women, and Persons with
Disabilities Act, to LGBTQ business enterprises, to
veteran-owned business enterprises, and to business
enterprises located in environmental justice
communities. The diversity composition goals of the
plan may include eligible expenditures in areas for
vendor or supplier opportunities in addition to
development and construction of the project, and may
exclude from eligible expenditures materials and
services with limited market availability, limited
production and availability from suppliers in the
United States, such as solar panels and storage
batteries, and material and services that are subject
to critical energy infrastructure or cybersecurity
requirements or restrictions. The plan may provide
that the diversity composition goals may be met
through Tier 1 Direct or Tier 2 subcontracting
expenditures or a combination thereof for the project.
(C) The plan shall provide for, but not be limited
to: (i) internal initiatives, including multi-tier
initiatives, by the applicant or owner, or by its
engineering, procurement and construction contractor
if one is used for the project, which for purposes of
this paragraph (11) shall be referred to as the EPC

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contractor, to enable diverse businesses to be
considered fairly for selection to provide materials
and services; (ii) requirements for the applicant or
owner or its EPC contractor to proactively solicit and
utilize diverse businesses to provide materials and
services; and (iii) requirements for the applicant or
owner or its EPC contractor to hire a diverse
workforce for the project. The plan shall include a
description of the applicant's or owner's diversity
recruiting efforts both for the project and for other
areas of the applicant's or owner's business
operations. The plan shall provide for the imposition
of financial penalties on the applicant's or owner's
EPC contractor for failure to exercise best efforts to
comply with and execute the EPC contractor's diversity
obligations under the plan. The plan may provide for
the applicant or owner to set aside a portion of the
work on the project to serve as an incubation program
for qualified businesses, as specified in the plan,
owned by minority persons, women, persons with
disabilities, LGBTQ persons, and veterans, and
businesses located in environmental justice
communities, seeking to enter the renewable energy
industry.
(D) The applicant or owner may submit a revised or
updated plan to the Commission from time to time as

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circumstances warrant. The applicant or owner shall
file annual reports with the Commission detailing the
applicant's or owner's progress in implementing its
plan and achieving its goals and any modifications the
applicant or owner has made to its plan to better
achieve its diversity, equity and inclusion goals. The
applicant or owner shall file a final report on the
fifth June 1 following the commercial operation date
of the new renewable energy resource or new energy
storage facility, but the applicant or owner shall
thereafter continue to be subject to applicable
reporting requirements of Section 5-117 of the Public
Utilities Act.
(c-10) Equity accountability system. It is the purpose of
this subsection (c-10) to create an equity accountability
system, which includes the minimum equity standards for all
renewable energy procurements, the equity category of the
Adjustable Block Program, and the equity prioritization for
noncompetitive procurements, that is successful in advancing
priority access to the clean energy economy for businesses and
workers from communities that have been excluded from economic
opportunities in the energy sector, have been subject to
disproportionate levels of pollution, and have
disproportionately experienced negative public health
outcomes. Further, it is the purpose of this subsection to
ensure that this equity accountability system is successful in

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advancing equity across Illinois by providing access to the
clean energy economy for businesses and workers from
communities that have been historically excluded from economic
opportunities in the energy sector, have been subject to
disproportionate levels of pollution, and have
disproportionately experienced negative public health
outcomes.
(1) Minimum equity standards. The Agency shall create
programs with the purpose of increasing access to and
development of equity eligible contractors, who are prime
contractors and subcontractors, across all of the programs
it manages. All applications for renewable energy credit
procurements shall comply with specific minimum equity
commitments. Starting in the delivery year immediately
following the next long-term renewable resources
procurement plan, at least 10% of the project workforce
for each entity participating in a procurement program
outlined in this subsection (c-10) must be done by equity
eligible persons or equity eligible contractors. The
Agency shall increase the minimum percentage each delivery
year thereafter by increments that ensure a statewide
average of 30% of the project workforce for each entity
participating in a procurement program is done by equity
eligible persons or equity eligible contractors by 2030.
The Agency shall propose a schedule of percentage
increases to the minimum equity standards in its draft

HB3758 - 149 - LRB104 12225 JDS 22331 b
revised renewable energy resources procurement plan
submitted to the Commission for approval pursuant to
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. In determining these annual
increases, the Agency shall have the discretion to
establish different minimum equity standards for different
types of procurements and different regions of the State
if the Agency finds that doing so will further the
purposes of this subsection (c-10). The proposed schedule
of annual increases shall be revisited and updated on an
annual basis. Revisions shall be developed with
stakeholder input, including from equity eligible persons,
equity eligible contractors, clean energy industry
representatives, and community-based organizations that
work with such persons and contractors.
(A) At the start of each delivery year, the Agency
shall require a compliance plan from each entity
participating in a procurement program of subsection
(c) of this Section that demonstrates how they will
achieve compliance with the minimum equity standard
percentage for work completed in that delivery year.
If an entity applies for its approved vendor or
designee status between delivery years, the Agency
shall require a compliance plan at the time of
application.
(B) Halfway through each delivery year, the Agency

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shall require each entity participating in a
procurement program to confirm that it will achieve
compliance in that delivery year, when applicable. The
Agency may offer corrective action plans to entities
that are not on track to achieve compliance.
(C) At the end of each delivery year, each entity
participating and completing work in that delivery
year in a procurement program of subsection (c) shall
submit a report to the Agency that demonstrates how it
achieved compliance with the minimum equity standards
percentage for that delivery year.
(D) The Agency shall prohibit participation in
procurement programs by an approved vendor or
designee, as applicable, or entities with which an
approved vendor or designee, as applicable, shares a
common parent company if an approved vendor or
designee, as applicable, failed to meet the minimum
equity standards for the prior delivery year. Waivers
approved for lack of equity eligible persons or equity
eligible contractors in a geographic area of a project
shall not count against the approved vendor or
designee. The Agency shall offer a corrective action
plan for any such entities to assist them in obtaining
compliance and shall allow continued access to
procurement programs upon an approved vendor or
designee demonstrating compliance.

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(E) The Agency shall pursue efficiencies achieved
by combining with other approved vendor or designee
reporting.
(2) Equity accountability system within the Adjustable
Block program. The equity category described in item (vi)
of subparagraph (K) of subsection (c) is only available to
applicants that are equity eligible contractors.
(3) Equity accountability system within competitive
procurements. Through its long-term renewable resources
procurement plan, the Agency shall develop requirements
for ensuring that competitive procurement processes,
including utility-scale solar, utility-scale wind, and
brownfield site photovoltaic projects, advance the equity
goals of this subsection (c-10). Subject to Commission
approval, the Agency shall develop bid application
requirements and a bid evaluation methodology for ensuring
that utilization of equity eligible contractors, whether
as bidders or as participants on project development, is
optimized, including requiring that winning or successful
applicants for utility-scale projects are or will partner
with equity eligible contractors and giving preference to
bids through which a higher portion of contract value
flows to equity eligible contractors. To the extent
practicable, entities participating in competitive
procurements shall also be required to meet all the equity
accountability requirements for approved vendors and their

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designees under this subsection (c-10). In developing
these requirements, the Agency shall also consider whether
equity goals can be further advanced through additional
measures.
(4) In the first revision to the long-term renewable
energy resources procurement plan and each revision
thereafter, the Agency shall include the following:
(A) The current status and number of equity
eligible contractors listed in the Energy Workforce
Equity Database designed in subsection (c-25),
including the number of equity eligible contractors
with current certifications as issued by the Agency.
(B) A mechanism for measuring, tracking, and
reporting project workforce at the approved vendor or
designee level, as applicable, which shall include a
measurement methodology and records to be made
available for audit by the Agency or the Program
Administrator.
(C) A program for approved vendors, designees,
eligible persons, and equity eligible contractors to
receive trainings, guidance, and other support from
the Agency or its designee regarding the equity
category outlined in item (vi) of subparagraph (K) of
paragraph (1) of subsection (c) and in meeting the
minimum equity standards of this subsection (c-10).
(D) A process for certifying equity eligible

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contractors and equity eligible persons. The
certification process shall coordinate with the Energy
Workforce Equity Database set forth in subsection
(c-25).
(E) An application for waiver of the minimum
equity standards of this subsection, which the Agency
shall have the discretion to grant in rare
circumstances. The Agency may grant such a waiver
where the applicant provides evidence of significant
efforts toward meeting the minimum equity commitment,
including: use of the Energy Workforce Equity
Database; efforts to hire or contract with entities
that hire eligible persons; and efforts to establish
contracting relationships with eligible contractors.
The Agency shall support applicants in understanding
the Energy Workforce Equity Database and other
resources for pursuing compliance of the minimum
equity standards. Waivers shall be project-specific,
unless the Agency deems it necessary to grant a waiver
across a portfolio of projects, and in effect for no
longer than one year. Any waiver extension or
subsequent waiver request from an applicant shall be
subject to the requirements of this Section and shall
specify efforts made to reach compliance. When
considering whether to grant a waiver, and to what
extent, the Agency shall consider the degree to which

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similarly situated applicants have been able to meet
these minimum equity commitments. For repeated waiver
requests for specific lack of eligible persons or
eligible contractors available, the Agency shall make
recommendations to target recruitment to add such
eligible persons or eligible contractors to the
database.
(5) The Agency shall collect information about work on
projects or portfolios of projects subject to these
minimum equity standards to ensure compliance with this
subsection (c-10). Reporting in furtherance of this
requirement may be combined with other annual reporting
requirements. Such reporting shall include proof of
certification of each equity eligible contractor or equity
eligible person during the applicable time period.
(6) The Agency shall keep confidential all information
and communication that provides private or personal
information.
(7) Modifications to the equity accountability system.
As part of the update of the long-term renewable resources
procurement plan to be initiated in 2023, or sooner if the
Agency deems necessary, the Agency shall determine the
extent to which the equity accountability system described
in this subsection (c-10) has advanced the goals of this
amendatory Act of the 102nd General Assembly, including
through the inclusion of equity eligible persons and

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equity eligible contractors in renewable energy credit
projects. If the Agency finds that the equity
accountability system has failed to meet those goals to
its fullest potential, the Agency may revise the following
criteria for future Agency procurements: (A) the
percentage of project workforce, or other appropriate
workforce measure, certified as equity eligible persons or
equity eligible contractors; (B) definitions for equity
investment eligible persons and equity investment eligible
community; and (C) such other modifications necessary to
advance the goals of this amendatory Act of the 102nd
General Assembly effectively. Such revised criteria may
also establish distinct equity accountability systems for
different types of procurements or different regions of
the State if the Agency finds that doing so will further
the purposes of such programs. Revisions shall be
developed with stakeholder input, including from equity
eligible persons, equity eligible contractors, and
community-based organizations that work with such persons
and contractors.
(c-15) Racial discrimination elimination powers and
process.
(1) Purpose. It is the purpose of this subsection to
empower the Agency and other State actors to remedy racial
discrimination in Illinois' clean energy economy as
effectively and expediently as possible, including through

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the use of race-conscious remedies, such as race-conscious
contracting and hiring goals, as consistent with State and
federal law.
(2) Racial disparity and discrimination review
process.
(A) Within one year after awarding contracts using
the equity actions processes established in this
Section, the Agency shall publish a report evaluating
the effectiveness of the equity actions point criteria
of this Section in increasing participation of equity
eligible persons and equity eligible contractors. The
report shall disaggregate participating workers and
contractors by race and ethnicity. The report shall be
forwarded to the Governor, the General Assembly, and
the Illinois Commerce Commission and be made available
to the public.
(B) As soon as is practicable thereafter, the
Agency, in consultation with the Department of
Commerce and Economic Opportunity, Department of
Labor, and other agencies that may be relevant, shall
commission and publish a disparity and availability
study that measures the presence and impact of
discrimination on minority businesses and workers in
Illinois' clean energy economy. The Agency may hire
consultants and experts to conduct the disparity and
availability study, with the retention of those

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consultants and experts exempt from the requirements
of Section 20-10 of the Illinois Procurement Code. The
Illinois Power Agency shall forward a copy of its
findings and recommendations to the Governor, the
General Assembly, and the Illinois Commerce
Commission. If the disparity and availability study
establishes a strong basis in evidence that there is
discrimination in Illinois' clean energy economy, the
Agency, Department of Commerce and Economic
Opportunity, Department of Labor, Department of
Corrections, and other appropriate agencies shall take
appropriate remedial actions, including race-conscious
remedial actions as consistent with State and federal
law, to effectively remedy this discrimination. Such
remedies may include modification of the equity
accountability system as described in subsection
(c-10).
(c-20) Program data collection.
(1) Purpose. Data collection, data analysis, and
reporting are critical to ensure that the benefits of the
clean energy economy provided to Illinois residents and
businesses are equitably distributed across the State. The
Agency shall collect data from program applicants in order
to track and improve equitable distribution of benefits
across Illinois communities for all procurements the
Agency conducts. The Agency shall use this data to, among

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other things, measure any potential impact of racial
discrimination on the distribution of benefits and provide
information necessary to correct any discrimination
through methods consistent with State and federal law.
(2) Agency collection of program data. The Agency
shall collect demographic and geographic data for each
entity awarded contracts under any Agency-administered
program. The Agency shall collect this data on an annual
basis for all systems energized during the applicable
annual period, but shall allow entities awarded contracts
under any Agency-administered program to elect to report
data exclusively on a project-by-project basis.
(3) Required information to be collected. The Agency
shall collect the following information from applicants
and program participants where applicable:
(A) demographic information, including racial or
ethnic identity for real persons employed, contracted,
or subcontracted through the program and owners of
businesses or entities that apply to receive renewable
energy credits from the Agency;
(B) geographic location of the residency of real
persons employed, contracted, or subcontracted through
the program and geographic location of the
headquarters of the business or entity that applies to
receive renewable energy credits from the Agency; and
(C) any other information the Agency determines is

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necessary for the purpose of achieving the purpose of
this subsection.
(4) Publication of collected information. The Agency
shall publish, at least annually, information on the
demographics of program participants on an aggregate
basis.
(5) Nothing in this subsection shall be interpreted to
limit the authority of the Agency, or other agency or
department of the State, to require or collect demographic
information from applicants of other State programs.
(c-25) Energy Workforce Equity Database.
(1) The Agency, in consultation with the Department of
Commerce and Economic Opportunity, shall create an Energy
Workforce Equity Database, and may contract with a third
party to do so ("database program administrator"). If the
Department decides to contract with a third party, that
third party shall be exempt from the requirements of
Section 20-10 of the Illinois Procurement Code. The Energy
Workforce Equity Database shall be a searchable database
of suppliers, vendors, and subcontractors for clean energy
industries that is:
(A) publicly accessible;
(B) easy for people to find and use;
(C) organized by company specialty or field;
(D) region-specific; and
(E) populated with information including, but not

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limited to, contacts for suppliers, vendors, or
subcontractors who are minority and women-owned
business enterprise certified or who participate or
have participated in any of the programs described in
this Act.
(2) The Agency shall create an easily accessible,
public facing online tool using the database information
that includes, at a minimum, the following:
(A) a map of environmental justice and equity
investment eligible communities;
(B) job postings and recruiting opportunities;
(C) a means by which recruiting clean energy
companies can find and interact with current or former
participants of clean energy workforce training
programs;
(D) information on workforce training service
providers and training opportunities available to
prospective workers;
(E) renewable energy company diversity reporting;
(F) a list of equity eligible contractors with
their contact information, types of work performed,
and locations worked in;
(G) reporting on outcomes of the programs
described in the workforce programs of the Energy
Transition Act, including information such as, but not
limited to, retention rate, graduation rate, and

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placement rates of trainees; and
(H) information about the Jobs and Environmental
Justice Grant Program, the Clean Energy Jobs and
Justice Fund, and other sources of capital.
(3) The Agency shall ensure the database is regularly
updated to ensure information is current and shall
coordinate with the Department of Commerce and Economic
Opportunity to ensure that it includes information on
individuals and entities that are or have participated in
the Clean Jobs Workforce Network Program, Clean Energy
Contractor Incubator Program, Returning Residents Clean
Jobs Training Program, or Clean Energy Primes Contractor
Accelerator Program.
(c-30) Enforcement of minimum equity standards. All
entities seeking renewable energy credits must submit an
annual report to demonstrate compliance with each of the
equity commitments required under subsection (c-10). If the
Agency concludes the entity has not met or maintained its
minimum equity standards required under the applicable
subparagraphs under subsection (c-10), the Agency shall deny
the entity's ability to participate in procurement programs in
subsection (c), including by withholding approved vendor or
designee status. The Agency may require the entity to enter
into a corrective action plan. An entity that is not
recertified for failing to meet required equity actions in
subparagraph (c-10) may reapply once they have a corrective

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action plan and achieve compliance with the minimum equity
standards.
(d) Clean coal portfolio standard.
(1) The procurement plans shall include electricity
generated using clean coal. Each utility shall enter into
one or more sourcing agreements with the initial clean
coal facility, as provided in paragraph (3) of this
subsection (d), covering electricity generated by the
initial clean coal facility representing at least 5% of
each utility's total supply to serve the load of eligible
retail customers in 2015 and each year thereafter, as
described in paragraph (3) of this subsection (d), subject
to the limits specified in paragraph (2) of this
subsection (d). It is the goal of the State that by January
1, 2025, 25% of the electricity used in the State shall be
generated by cost-effective clean coal facilities. For
purposes of this subsection (d), "cost-effective" means
that the expenditures pursuant to such sourcing agreements
do not cause the limit stated in paragraph (2) of this
subsection (d) to be exceeded and do not exceed cost-based
benchmarks, which shall be developed to assess all
expenditures pursuant to such sourcing agreements covering
electricity generated by clean coal facilities, other than
the initial clean coal facility, by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be

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subject to Commission review and approval.
A utility party to a sourcing agreement shall
immediately retire any emission credits that it receives
in connection with the electricity covered by such
agreement.
Utilities shall maintain adequate records documenting
the purchases under the sourcing agreement to comply with
this subsection (d) and shall file an accounting with the
load forecast that must be filed with the Agency by July 15
of each year, in accordance with subsection (d) of Section
16-111.5 of the Public Utilities Act.
A utility shall be deemed to have complied with the
clean coal portfolio standard specified in this subsection
(d) if the utility enters into a sourcing agreement as
required by this subsection (d).
(2) For purposes of this subsection (d), the required
execution of sourcing agreements with the initial clean
coal facility for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied by the electric utility to
eligible retail customers in the planning year ending
immediately prior to the agreement's execution. For
purposes of this subsection (d), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (d), the total amount paid for

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electric service includes without limitation amounts paid
for supply, transmission, distribution, surcharges and
add-on taxes.
Notwithstanding the requirements of this subsection
(d), the total amount paid under sourcing agreements with
clean coal facilities pursuant to the procurement plan for
any given year shall be reduced by an amount necessary to
limit the annual estimated average net increase due to the
costs of these resources included in the amounts paid by
eligible retail customers in connection with electric
service to:
(A) in 2010, no more than 0.5% of the amount paid
per kilowatthour by those customers during the year
ending May 31, 2009;
(B) in 2011, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2010 or 1% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009;
(C) in 2012, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2011 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2009;
(D) in 2013, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers

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during the year ending May 31, 2012 or 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009; and
(E) thereafter, the total amount paid under
sourcing agreements with clean coal facilities
pursuant to the procurement plan for any single year
shall be reduced by an amount necessary to limit the
estimated average net increase due to the cost of
these resources included in the amounts paid by
eligible retail customers in connection with electric
service to no more than the greater of (i) 2.015% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2009 or (ii) the
incremental amount per kilowatthour paid for these
resources in 2013. These requirements may be altered
only as provided by statute.
No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General
Assembly its findings as to whether that limitation unduly
constrains the amount of electricity generated by
cost-effective clean coal facilities that is covered by
sourcing agreements.
(3) Initial clean coal facility. In order to promote
development of clean coal facilities in Illinois, each

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electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal
facility by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval
by the General Assembly. The Agency and the Commission
shall have authority to inspect all books and records
associated with the initial clean coal facility during the
term of such a sourcing agreement. A utility's sourcing
agreement for electricity produced by the initial clean
coal facility shall include:
(A) a formula contractual price (the "contract
price") approved pursuant to paragraph (4) of this
subsection (d), which shall:
(i) be determined using a cost of service
methodology employing either a level or deferred
capital recovery component, based on a capital

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structure consisting of 45% equity and 55% debt,
and a return on equity as may be approved by the
Federal Energy Regulatory Commission, which in any
case may not exceed the lower of 11.5% or the rate
of return approved by the General Assembly
pursuant to paragraph (4) of this subsection (d);
and
(ii) provide that all miscellaneous net
revenue, including but not limited to net revenue
from the sale of emission allowances, if any,
substitute natural gas, if any, grants or other
support provided by the State of Illinois or the
United States Government, firm transmission
rights, if any, by-products produced by the
facility, energy or capacity derived from the
facility and not covered by a sourcing agreement
pursuant to paragraph (3) of this subsection (d)
or item (5) of subsection (d) of Section 16-115 of
the Public Utilities Act, whether generated from
the synthesis gas derived from coal, from SNG, or
from natural gas, shall be credited against the
revenue requirement for this initial clean coal
facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price

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for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean
coal facility in each hour an amount of energy
equal to all clean coal energy made available from
the initial clean coal facility during such hour
times a fraction, the numerator of which is such
utility's retail market sales of electricity
(expressed in kilowatthours sold) in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount purchased by the utility
in any year will be limited by paragraph (2) of
this subsection (d); and

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(iv) be considered pre-existing contracts in
such utility's procurement plans for eligible
retail customers;
(C) contract for differences provisions, which
shall:
(i) require the utility party to such sourcing
agreement to contract with the initial clean coal
facility in each hour with respect to an amount of
energy equal to all clean coal energy made
available from the initial clean coal facility
during such hour times a fraction, the numerator
of which is such utility's retail market sales of
electricity (expressed in kilowatthours sold) in
the utility's service territory in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount paid by the utility in
any year will be limited by paragraph (2) of this

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subsection (d);
(ii) provide that the utility's payment
obligation in respect of the quantity of
electricity determined pursuant to the preceding
clause (i) shall be limited to an amount equal to
(1) the difference between the contract price
determined pursuant to subparagraph (A) of
paragraph (3) of this subsection (d) and the
day-ahead price for electricity delivered to the
regional transmission organization market of the
utility that is party to such sourcing agreement
(or any successor delivery point at which such
utility's supply obligations are financially
settled on an hourly basis) (the "reference
price") on the day preceding the day on which the
electricity is delivered to the initial clean coal
facility busbar, multiplied by (2) the quantity of
electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical
delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;

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(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy
Regulatory Commission and to purchasers in
accordance with applicable laws governing
cost-based wholesale power contracts;
(iv) permit the Illinois Power Agency to
assume ownership of the initial clean coal
facility, without monetary consideration and
otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract
term;
(v) require the owner of the initial clean
coal facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from

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the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate
that the initial clean coal facility captured and
sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior
years has failed, resulting in the release of
carbon dioxide into the atmosphere, the owner of
the facility must offset excess emissions. Any
such carbon offsets must be permanent, additional,
verifiable, real, located within the State of
Illinois, and legally and practicably enforceable.
The cost of such offsets for the facility that are
not recoverable shall not exceed $15 million in
any given year. No costs of any such purchases of
carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its

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designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in
the course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to

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determine the justness, reasonableness, and
prudence of the inputs to the formula referenced
in subparagraphs (A)(i) through (A)(iii) of
paragraph (3) of this subsection (d), prior to an
adjustment in those inputs including, without
limitation, the capital structure and return on
equity, fuel costs, and other operations and
maintenance costs and (2) to approve the costs to
be passed through to customers under the sourcing
agreement by which the utility satisfies its
statutory obligations. Commission review shall
occur no less than every 3 years, regardless of
whether any adjustments have been proposed, and
shall be completed within 9 months;
(viii) limit the utility's obligation to such
amount as the utility is allowed to recover
through tariffs filed with the Commission,
provided that neither the clean coal facility nor
the utility waives any right to assert federal
pre-emption or any other argument in response to a
purported disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being

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delivered to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or
the contract for differences provisions;
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been
approved by the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal
Power Act;
(xii) provide that any changes to the terms of
the contract, insofar as such changes relate to
the power purchase provisions, are subject to
review under the public interest standard applied
by the Federal Energy Regulatory Commission
pursuant to Sections 205 and 206 of the Federal
Power Act; and
(xiii) conform with customary lender
requirements in power purchase agreements used as
the basis for financing non-utility generators.
(4) Effective date of sourcing agreements with the
initial clean coal facility. Any proposed sourcing

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agreement with the initial clean coal facility shall not
become effective unless the following reports are prepared
and submitted and authorizations and approvals obtained:
(i) Facility cost report. The owner of the initial
clean coal facility shall submit to the Commission,
the Agency, and the General Assembly a front-end
engineering and design study, a facility cost report,
method of financing (including but not limited to
structure and associated costs), and an operating and
maintenance cost quote for the facility (collectively
"facility cost report"), which shall be prepared in
accordance with the requirements of this paragraph (4)
of subsection (d) of this Section, and shall provide
the Commission and the Agency access to the work
papers, relied upon documents, and any other backup
documentation related to the facility cost report.
(ii) Commission report. Within 6 months following
receipt of the facility cost report, the Commission,
in consultation with the Agency, shall submit a report
to the General Assembly setting forth its analysis of
the facility cost report. Such report shall include,
but not be limited to, a comparison of the costs
associated with electricity generated by the initial
clean coal facility to the costs associated with
electricity generated by other types of generation
facilities, an analysis of the rate impacts on

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residential and small business customers over the life
of the sourcing agreements, and an analysis of the
likelihood that the initial clean coal facility will
commence commercial operation by and be delivering
power to the facility's busbar by 2016. To assist in
the preparation of its report, the Commission, in
consultation with the Agency, may hire one or more
experts or consultants, the costs of which shall be
paid for by the owner of the initial clean coal
facility. The Commission and Agency may begin the
process of selecting such experts or consultants prior
to receipt of the facility cost report.
(iii) General Assembly approval. The proposed
sourcing agreements shall not take effect unless,
based on the facility cost report and the Commission's
report, the General Assembly enacts authorizing
legislation approving (A) the projected price, stated
in cents per kilowatthour, to be charged for
electricity generated by the initial clean coal
facility, (B) the projected impact on residential and
small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the

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Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding
that the sourcing agreement is prudent and reasonable.
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms
detailing the estimated capital costs payable to one
or more contractors or suppliers for the engineering,
procurement and construction of the components
comprising the initial clean coal facility and the
estimated costs of operation and maintenance of the
facility. The facility cost report shall include:
(i) an estimate of the capital cost of the
core plant based on one or more front end
engineering and design studies for the
gasification island and related facilities. The
core plant shall include all civil, structural,
mechanical, electrical, control, and safety
systems.
(ii) an estimate of the capital cost of the
balance of the plant, including any capital costs

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associated with sequestration of carbon dioxide
emissions and all interconnects and interfaces
required to operate the facility, such as
transmission of electricity, construction or
backfeed power supply, pipelines to transport
substitute natural gas or carbon dioxide, potable
water supply, natural gas supply, water supply,
water discharge, landfill, access roads, and coal
delivery.
The quoted construction costs shall be expressed
in nominal dollars as of the date that the quote is
prepared and shall include capitalized financing costs
during construction, taxes, insurance, and other
owner's costs, and an assumed escalation in materials
and labor beyond the date as of which the construction
cost quote is expressed.
(B) The front end engineering and design study for
the gasification island and the cost study for the
balance of plant shall include sufficient design work
to permit quantification of major categories of
materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,

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maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms
performing the construction cost quote, potential
vendors under long-term service agreements and plant
operating agreements, or recognized third party plant
operator or operators.
The operating and maintenance cost quote
(including the cost of the front end engineering and
design study) shall be expressed in nominal dollars as
of the date that the quote is prepared and shall
include taxes, insurance, and other owner's costs, and
an assumed escalation in materials and labor beyond
the date as of which the operating and maintenance
cost quote is expressed.
(D) The facility cost report shall also include an
analysis of the initial clean coal facility's ability
to deliver power and energy into the applicable
regional transmission organization markets and an
analysis of the expected capacity factor for the

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initial clean coal facility.
(E) Amounts paid to third parties unrelated to the
owner or owners of the initial clean coal facility to
prepare the core plant construction cost quote,
including the front end engineering and design study,
and the operating and maintenance cost quote will be
reimbursed through Coal Development Bonds.
(5) Re-powering and retrofitting coal-fired power
plants previously owned by Illinois utilities to qualify
as clean coal facilities. During the 2009 procurement
planning process and thereafter, the Agency and the
Commission shall consider sourcing agreements covering
electricity generated by power plants that were previously
owned by Illinois utilities and that have been or will be
converted into clean coal facilities, as defined by
Section 1-10 of this Act. Pursuant to such procurement
planning process, the owners of such facilities may
propose to the Agency sourcing agreements with utilities
and alternative retail electric suppliers required to
comply with subsection (d) of this Section and item (5) of
subsection (d) of Section 16-115 of the Public Utilities
Act, covering electricity generated by such facilities. In
the case of sourcing agreements that are power purchase
agreements, the contract price for electricity sales shall
be established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,

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the contract price from which the reference price is
subtracted shall be established on a cost of service
basis. The Agency and the Commission may approve any such
utility sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal
facilities during the term of any such contract.
(6) Costs incurred under this subsection (d) or
pursuant to a contract entered into under this subsection
(d) shall be deemed prudently incurred and reasonable in
amount and the electric utility shall be entitled to full
cost recovery pursuant to the tariffs filed with the
Commission.
(d-5) Zero emission standard.
(1) Beginning with the delivery year commencing on
June 1, 2017, the Agency shall, for electric utilities
that serve at least 100,000 retail customers in this
State, procure contracts with zero emission facilities
that are reasonably capable of generating cost-effective
zero emission credits in an amount approximately equal to
16% of the actual amount of electricity delivered by each
electric utility to retail customers in the State during
calendar year 2014. For an electric utility serving fewer

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than 100,000 retail customers in this State that
requested, under Section 16-111.5 of the Public Utilities
Act, that the Agency procure power and energy for all or a
portion of the utility's Illinois load for the delivery
year commencing June 1, 2016, the Agency shall procure
contracts with zero emission facilities that are
reasonably capable of generating cost-effective zero
emission credits in an amount approximately equal to 16%
of the portion of power and energy to be procured by the
Agency for the utility. The duration of the contracts
procured under this subsection (d-5) shall be for a term
of 10 years ending May 31, 2027. The quantity of zero
emission credits to be procured under the contracts shall
be all of the zero emission credits generated by the zero
emission facility in each delivery year; however, if the
zero emission facility is owned by more than one entity,
then the quantity of zero emission credits to be procured
under the contracts shall be the amount of zero emission
credits that are generated from the portion of the zero
emission facility that is owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section for the 5
delivery years beginning June 1, 2017.
The procurement process shall be subject to the
following provisions:

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(A) Those zero emission facilities that intend to
participate in the procurement shall submit to the
Agency the following eligibility information for each
zero emission facility on or before the date
established by the Agency:
(i) the in-service date and remaining useful
life of the zero emission facility;
(ii) the amount of power generated annually
for each of the years 2005 through 2015, and the
projected zero emission credits to be generated
over the remaining useful life of the zero
emission facility, which shall be used to
determine the capability of each facility;
(iii) the annual zero emission facility cost
projections, expressed on a per megawatt hour
megawatthour basis, over the next 6 delivery
years, which shall include the following:
operation and maintenance expenses; fully
allocated overhead costs, which shall be allocated
using the methodology developed by the Institute
for Nuclear Power Operations; fuel expenditures;
non-fuel capital expenditures; spent fuel
expenditures; a return on working capital; the
cost of operational and market risks that could be
avoided by ceasing operation; and any other costs
necessary for continued operations, provided that

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"necessary" means, for purposes of this item
(iii), that the costs could reasonably be avoided
only by ceasing operations of the zero emission
facility; and
(iv) a commitment to continue operating, for
the duration of the contract or contracts executed
under the procurement held under this subsection
(d-5), the zero emission facility that produces
the zero emission credits to be procured in the
procurement.
The information described in item (iii) of this
subparagraph (A) may be submitted on a confidential
basis and shall be treated and maintained by the
Agency, the procurement administrator, and the
Commission as confidential and proprietary and exempt
from disclosure under subparagraphs (a) and (g) of
paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of Attorney General shall
have access to, and maintain the confidentiality of,
such information pursuant to Section 6.5 of the
Attorney General Act.
(B) The price for each zero emission credit
procured under this subsection (d-5) for each delivery
year shall be in an amount that equals the Social Cost
of Carbon, expressed on a price per megawatt hour
megawatthour basis. However, to ensure that the

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procurement remains affordable to retail customers in
this State if electricity prices increase, the price
in an applicable delivery year shall be reduced below
the Social Cost of Carbon by the amount ("Price
Adjustment") by which the market price index for the
applicable delivery year exceeds the baseline market
price index for the consecutive 12-month period ending
May 31, 2016. If the Price Adjustment is greater than
or equal to the Social Cost of Carbon in an applicable
delivery year, then no payments shall be due in that
delivery year. The components of this calculation are
defined as follows:
(i) Social Cost of Carbon: The Social Cost of
Carbon is $16.50 per megawatt hour megawatthour,
which is based on the U.S. Interagency Working
Group on Social Cost of Carbon's price in the
August 2016 Technical Update using a 3% discount
rate, adjusted for inflation for each year of the
program. Beginning with the delivery year
commencing June 1, 2023, the price per megawatt
hour megawatthour shall increase by $1 per
megawatt hour megawatthour, and continue to
increase by an additional $1 per megawatt hour
megawatthour each delivery year thereafter.
(ii) Baseline market price index: The baseline
market price index for the consecutive 12-month

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period ending May 31, 2016 is $31.40 per megawatt
hour megawatthour, which is based on the sum of
(aa) the average day-ahead energy price across all
hours of such 12-month period at the PJM
Interconnection LLC Northern Illinois Hub, (bb)
50% multiplied by the Base Residual Auction, or
its successor, capacity price for the rest of the
RTO zone group determined by PJM Interconnection
LLC, divided by 24 hours per day, and (cc) 50%
multiplied by the Planning Resource Auction, or
its successor, capacity price for Zone 4
determined by the Midcontinent Independent System
Operator, Inc., divided by 24 hours per day.
(iii) Market price index: The market price
index for a delivery year shall be the sum of
projected energy prices and projected capacity
prices determined as follows:
(aa) Projected energy prices: the
projected energy prices for the applicable
delivery year shall be calculated once for the
year using the forward market price for the
PJM Interconnection, LLC Northern Illinois
Hub. The forward market price shall be
calculated as follows: the energy forward
prices for each month of the applicable
delivery year averaged for each trade date

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during the calendar year immediately preceding
that delivery year to produce a single energy
forward price for the delivery year. The
forward market price calculation shall use
data published by the Intercontinental
Exchange, or its successor.
(bb) Projected capacity prices:
(I) For the delivery years commencing
June 1, 2017, June 1, 2018, and June 1,
2019, the projected capacity price shall
be equal to the sum of (1) 50% multiplied
by the Base Residual Auction, or its
successor, price for the rest of the RTO
zone group as determined by PJM
Interconnection LLC, divided by 24 hours
per day and, (2) 50% multiplied by the
resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where
such price is determined by the
Midcontinent Independent System Operator,
Inc.
(II) For the delivery year commencing

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June 1, 2020, and each year thereafter,
the projected capacity price shall be
equal to the sum of (1) 50% multiplied by
the Base Residual Auction, or its
successor, price for the ComEd zone as
determined by PJM Interconnection LLC,
divided by 24 hours per day, and (2) 50%
multiplied by the resource auction price
determined in the resource auction
administered by the Midcontinent
Independent System Operator, Inc., in
which the largest percentage of load
cleared for Local Resource Zone 4, divided
by 24 hours per day, and where such price
is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have
the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission
organization.
(C) No later than 45 days after June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
publish its proposed zero emission standard
procurement plan. The plan shall be consistent with

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

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

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successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur
dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of
this State;
(ii) specifically address how the selection of
winning bids takes into account the incremental
environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements
held under Public Act 99-906 and would have ceased
to exist if the procurements had not been held,
such as the preservation of zero emission
facilities;
(iii) quantify the environmental benefit of
preserving the resources identified in item (ii)
of this subparagraph (C-5), including the
following:
(aa) the value of avoided greenhouse gas
emissions measured as the product of the zero
emission facilities' output over the contract
term multiplied by the U.S. Environmental

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Protection Agency eGrid subregion carbon
dioxide emission rate and the U.S. Interagency
Working Group on Social Cost of Carbon's price
in the August 2016 Technical Update using a 3%
discount rate, adjusted for inflation for each
delivery year; and
(bb) the costs of replacement with other
zero carbon dioxide resources, including wind
and photovoltaic, based upon the simple
average of the following:
(I) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale wind projects in the
procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of this Section; and
(II) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale solar projects and
brownfield site photovoltaic projects in
the procurement events specified in item
(ii) of subparagraph (G) of paragraph (1)
of subsection (c) of this Section and,
after January 1, 2015, renewable energy

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credits from photovoltaic distributed
generation projects in procurement events
held under subsection (c) of this Section.
Each utility shall enter into binding contractual
arrangements with the winning suppliers.
The procurement described in this subsection
(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines
under this subparagraph and subparagraphs (C) and (D)
of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)
shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a
procurement process on June 1, 2017 (the effective
date of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate

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

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reasonable efforts, it has been unable to
overcome. In such event, the zero emission
facility shall be excused from performance for the
duration of the event, including, but not limited
to, delivery of zero emission credits, and no
payment shall be due to the zero emission facility
during the duration of the event.
(ii) A zero emission facility shall be
permitted to terminate the contract if legislation
is enacted into law by the General Assembly that
imposes or authorizes a new tax, special
assessment, or fee on the generation of
electricity, the ownership or leasehold of a
generating unit, or the privilege or occupation of
such generation, ownership, or leasehold of
generation units by a zero emission facility.
However, the provisions of this item (ii) do not
apply to any generally applicable tax, special
assessment or fee, or requirements imposed by
federal law.
(iii) A zero emission facility shall be
permitted to terminate the contract in the event
that the resource requires capital expenditures in
excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it executed the
contract and that a prudent owner or operator of

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such resource would not undertake.
(iv) A zero emission facility shall be
permitted to terminate the contract in the event
the Nuclear Regulatory Commission terminates the
resource's license.
(F) If the zero emission facility elects to
terminate a contract under subparagraph (E) of this
paragraph (1), then the Commission shall reopen the
docket in which the Commission approved the zero
emission standard procurement plan under subparagraph
(C) of this paragraph (1) and, after notice and
hearing, enter an order acknowledging the contract
termination election if such termination is consistent
with the provisions of this subsection (d-5).
(2) For purposes of this subsection (d-5), the amount
paid per kilowatthour means the total amount paid for
electric service expressed on a per kilowatthour basis.
For purposes of this subsection (d-5), the total amount
paid for electric service includes, without limitation,
amounts paid for supply, transmission, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(d-5), the contracts executed under this subsection (d-5)
shall provide that the total of zero emission credits
procured under a procurement plan shall be subject to the
limitations of this paragraph (2). For each delivery year,

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

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

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payments received by the supplier over the relevant period
exceed the Average ZEC Payment, then the supplier shall
credit the difference back to the utility. The amount of
the credit shall be remitted to the applicable electric
utility no later than 120 days after the Agency's
determination, which the utility shall reflect as a credit
on its retail customer bills as soon as practicable;
however, the credit remitted to the utility shall not
exceed the total amount of payments received by the
facility under its contract.
For purposes of this Section, the Average ZEC Payment
shall be calculated by multiplying the quantity of zero
emission credits delivered under the contract times the
average contract price. The average contract price shall
be determined by subtracting the amount calculated under
subparagraph (B) of this paragraph (3) from the amount
calculated under subparagraph (A) of this paragraph (3),
as follows:
(A) The average of the Social Cost of Carbon, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract.
(B) The average of the market price indices, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract,
minus the baseline market price index, as defined in
subparagraph (B) of paragraph (1) of this subsection

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

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to avoid and not increase carbon emissions from electric
generation sources while continuing to ensure affordable,
stable, and reliable electricity to all citizens.
(B) Absent immediate action by the State to preserve
existing carbon-free energy resources, those resources may
retire, and the electric generation needs of Illinois'
retail customers may be met instead by facilities that
emit significant amounts of carbon pollution and other
harmful air pollutants at a high social and economic cost
until Illinois is able to develop other forms of clean
energy.
(C) The General Assembly finds that nuclear power
generation is necessary for the State's transition to 100%
clean energy, and ensuring continued operation of nuclear
plants advances environmental and public health interests
through providing carbon-free electricity while reducing
the air pollution profile of the Illinois energy
generation fleet.
(D) The clean energy attributes of nuclear generation
facilities support the State in its efforts to achieve
100% clean energy.
(E) The State currently invests in various forms of
clean energy, including, but not limited to, renewable
energy, energy efficiency, and low-emission vehicles,
among others.
(F) The Environmental Protection Agency commissioned

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an independent audit which provided a detailed assessment
of the financial condition of the Illinois nuclear fleet
to evaluate its financial viability and whether the
environmental benefits of such resources were at risk. The
report identified the risk of losing the environmental
benefits of several specific nuclear units. The report
also identified that the LaSalle County Generating Station
will continue to operate through 2026 and therefore is not
eligible to participate in the carbon mitigation credit
program.
(G) Nuclear plants provide carbon-free energy, which
helps to avoid many health-related negative impacts for
Illinois residents.
(H) The procurement of carbon mitigation credits
representing the environmental benefits of carbon-free
generation will further the State's efforts at achieving
100% clean energy and decarbonizing the electricity sector
in a safe, reliable, and affordable manner. Further, the
procurement of carbon emission credits will enhance the
health and welfare of Illinois residents through decreased
reliance on more highly polluting generation.
(I) The General Assembly therefore finds it necessary
to establish carbon mitigation credits to ensure decreased
reliance on more carbon-intensive energy resources, for
transitioning to a fully decarbonized electricity sector,
and to help ensure health and welfare of the State's

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residents.
(2) As used in this subsection:
"Baseline costs" means costs used to establish a customer
protection cap that have been evaluated through an independent
audit of a carbon-free energy resource conducted by the
Environmental Protection Agency that evaluated projected
annual costs for operation and maintenance expenses; fully
allocated overhead costs, which shall be allocated using the
methodology developed by the Institute for Nuclear Power
Operations; fuel expenditures; nonfuel capital expenditures;
spent fuel expenditures; a return on working capital; the cost
of operational and market risks that could be avoided by
ceasing operation; and any other costs necessary for continued
operations, provided that "necessary" means, for purposes of
this definition, that the costs could reasonably be avoided
only by ceasing operations of the carbon-free energy resource.
"Carbon mitigation credit" means a tradable credit that
represents the carbon emission reduction attributes of one
megawatt-hour of energy produced from a carbon-free energy
resource.
"Carbon-free energy resource" means a generation facility
that: (1) is fueled by nuclear power; and (2) is
interconnected to PJM Interconnection, LLC.
(3) Procurement.
(A) Beginning with the delivery year commencing on
June 1, 2022, the Agency shall, for electric utilities

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serving at least 3,000,000 retail customers in the State,
seek to procure contracts for no more than approximately
54,500,000 cost-effective carbon mitigation credits from
carbon-free energy resources because such credits are
necessary to support current levels of carbon-free energy
generation and ensure the State meets its carbon dioxide
emissions reduction goals. The Agency shall not make a
partial award of a contract for carbon mitigation credits
covering a fractional amount of a carbon-free energy
resource's projected output.
(B) Each carbon-free energy resource that intends to
participate in a procurement shall be required to submit
to the Agency the following information for the resource
on or before the date established by the Agency:
(i) the in-service date and remaining useful life
of the carbon-free energy resource;
(ii) the amount of power generated annually for
each of the past 10 years, which shall be used to
determine the capability of each facility;
(iii) a commitment to be reflected in any contract
entered into pursuant to this subsection (d-10) to
continue operating the carbon-free energy resource at
a capacity factor of at least 88% annually on average
for the duration of the contract or contracts executed
under the procurement held under this subsection
(d-10), except in an instance described in

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subparagraph (E) of paragraph (1) of subsection (d-5)
of this Section or made impracticable as a result of
compliance with law or regulation;
(iv) financial need and the risk of loss of the
environmental benefits of such resource, which shall
include the following information:
(I) the carbon-free energy resource's cost
projections, expressed on a per megawatt-hour
basis, over the next 5 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;
fuel expenditures; nonfuel capital expenditures;
spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this subitem (I), that the costs could
reasonably be avoided only by ceasing operations
of the carbon-free energy resource; and
(II) the carbon-free energy resource's revenue
projections, including energy, capacity, ancillary
services, any other direct State support, known or
anticipated federal attribute credits, known or

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

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

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delivery years, and then any subsequent delivery
years unless the PJM Interconnection, LLC applies
the Minimum Offer Price Rule to participating
carbon-free energy resources because they supply
carbon mitigation credits pursuant to this Section
at which time, upon notice by the carbon-free
energy resource to the Commission and subject to
the Commission's confirmation, the value under
this subitem shall be zero, as further described
in the carbon mitigation credit procurement plan;
and
(III) any value of monetized federal tax
credits, direct payments, or similar subsidy
provided to the carbon-free energy resource from
any unit of government that is not already
reflected in energy prices.
If the price-per-megawatt-hour calculation
performed under item (iii) of this subparagraph (C)
for a given delivery year results in a net positive
value, then the electric utility counterparty to the
contract shall multiply such net value by the
applicable contract quantity and remit the amount to
the supplier.
To protect retail customers from retail rate
impacts that may arise upon the initiation of carbon
policy changes, if the price-per-megawatt-hour

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calculation performed under item (iii) of this
subparagraph (C) for a given delivery year results in
a net negative value, then the supplier counterparty
to the contract shall multiply such net value by the
applicable contract quantity and remit such amount to
the electric utility counterparty. The electric
utility shall reflect such amounts remitted by
suppliers as a credit on its retail customer bills as
soon as practicable.
(iv) To ensure that retail customers in Northern
Illinois do not pay more for carbon mitigation credits
than the value such credits provide, and
notwithstanding the provisions of this subsection
(d-10), the Agency shall not accept bids for contracts
that exceed a customer protection cap equal to the
baseline costs of carbon-free energy resources.
The baseline costs for the applicable year shall
be the following:
(I) For the delivery year beginning June 1,
2022, the baseline costs shall be an amount equal
to $30.30 per megawatt-hour.
(II) For the delivery year beginning June 1,
2023, the baseline costs shall be an amount equal
to $32.50 per megawatt-hour.
(III) For the delivery year beginning June 1,
2024, the baseline costs shall be an amount equal

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to $33.43 per megawatt-hour.
(IV) For the delivery year beginning June 1,
2025, the baseline costs shall be an amount equal
to $33.50 per megawatt-hour.
(V) For the delivery year beginning June 1,
2026, the baseline costs shall be an amount equal
to $34.50 per megawatt-hour.
An Environmental Protection Agency consultant
forecast, included in a report issued April 14, 2021,
projects that a carbon-free energy resource has the
opportunity to earn on average approximately $30.28
per megawatt-hour, for the sale of energy and capacity
during the time period between 2022 and 2027.
Therefore, the sale of carbon mitigation credits
provides the opportunity to receive an additional
amount per megawatt-hour in addition to the projected
prices for energy and capacity.
Although actual energy and capacity prices may
vary from year-to-year, the General Assembly finds
that this customer protection cap will help ensure
that the cost of carbon mitigation credits will be
less than its value, based upon the social cost of
carbon identified in the Technical Support Document
issued in February 2021 by the U.S. Interagency
Working Group on Social Cost of Greenhouse Gases and
the PJM Interconnection, LLC carbon dioxide marginal

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

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

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carbon-free energy resources at prices that are within the
limits specified in this paragraph (3). As part of the
Commission's review and acceptance or rejection of the
procurement results, the Commission shall, in its public
notice of successful bidders:
(i) identify how the selected carbon-free energy
resources satisfy the public interest criteria
described in this paragraph (3) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur dioxide,
nitrogen oxide, and particulate matter emissions that
adversely affect the citizens of this State;
(ii) specifically address how the selection of
carbon-free energy resources takes into account the
incremental environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements held
under this amendatory Act of the 102nd General
Assembly and would have ceased to exist if the
procurements had not been held, such as the
preservation of carbon-free energy resources;
(iii) quantify the environmental benefit of
preserving the carbon-free energy resources procured
pursuant to this subsection (d-10), including the
following:
(I) an assessment value of avoided greenhouse

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gas emissions measured as the product of the
carbon-free energy resources' output over the
contract term, using generally accepted
methodologies for the valuation of avoided
emissions; and
(II) an assessment of costs of replacement
with other carbon-free energy resources and
renewable energy resources, including wind and
photovoltaic generation, based upon an assessment
of the prices paid for renewable energy credits
through programs and procurements conducted
pursuant to subsection (c) of Section 1-75 of this
Act, and the additional storage necessary to
produce the same or similar capability of matching
customer usage patterns.
(F) The procurements described in this paragraph (3),
including, but not limited to, the execution of all
contracts procured, shall be completed no later than
December 3, 2021. The procurement and plan approval
processes required by this paragraph (3) shall be
conducted in conjunction with the procurement and plan
approval processes required by Section 16-111.5 of the
Public Utilities Act, to the extent practicable. However,
the Agency and Commission may, as appropriate, modify the
various dates and timelines under this subparagraph and
subparagraphs (D) and (E) of this paragraph (3) to meet

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the December 3, 2021 contract execution deadline.
Following the completion of such procurements, and
consistent with this paragraph (3), the Agency shall
calculate the payments to be made under each contract in a
timely fashion.
(F-1) Costs incurred by the electric utility pursuant
to a contract authorized by this subsection (d-10) shall
be deemed prudently incurred and reasonable in amount, and
the electric utility shall be entitled to full cost
recovery pursuant to a tariff or tariffs filed with the
Commission.
(G) The counterparty electric utility shall retire all
carbon mitigation credits used to comply with the
requirements of this subsection (d-10).
(H) If a carbon-free energy resource is sold to
another owner, the rights, obligations, and commitments
under this subsection (d-10) shall continue to the
subsequent owner.
(I) This subsection (d-10) shall become inoperative on
January 1, 2028.
(e) The draft procurement plans are subject to public
comment, as required by Section 16-111.5 of the Public
Utilities Act.
(f) The Agency shall submit the final procurement plan to
the Commission. The Agency shall revise a procurement plan if
the Commission determines that it does not meet the standards

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set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility
to recover the costs incurred in preparation of the annual
procurement plan for the utility.
(h) The Agency shall assess fees to each bidder to recover
the costs incurred in connection with a competitive
procurement process.
(i) A renewable energy credit, carbon emission credit,
zero emission credit, or carbon mitigation credit can only be
used once to comply with a single portfolio or other standard
as set forth in subsection (c), subsection (d), or subsection
(d-5) of this Section, respectively. A renewable energy
credit, carbon emission credit, zero emission credit, or
carbon mitigation credit cannot be used to satisfy the
requirements of more than one standard. If more than one type
of credit is issued for the same megawatt hour of energy, only
one credit can be used to satisfy the requirements of a single
standard. After such use, the credit must be retired together
with any other credits issued for the same megawatt hour of
energy.
(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24;
103-580, eff. 12-8-23.)
(20 ILCS 3855/1-93 new)
Sec. 1-93. Energy storage resource procurements.
(a) The Agency shall develop a storage procurement plan 20

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that results in electric utilities contracting for energy
storage resources in the 21 following amounts:
(1) at least 1,500 megawatts of cumulative energy
storage capacity in the initial forward procurement
described in paragraph (2) of this subsection (a)
(2) at least 3,500 megawatts of cumulative energy
storage capacity by the end of delivery year 2026-27,
(3) at least 6,000 megawatts of cumulative energy
storage capacity by delivery year 2028-29,
(4) at least 9,000 megawatts of cumulative energy
storage capacity by delivery year 2030-31.
(5) at least 12,000 megawatts of cumulative energy
storage capacity by delivery year 2032-33; and
(6) at least 15,000 megawatts of cumulative energy
storage capacity by delivery year 2034-35
(b)(1) Within 180 days after the effective date of this
amendatory Act of the 104th General Assembly, the Agency shall
develop an energy storage procurement plan in accordance with
this Section and Section 16-111.5 of the Public Utilities Act.
(2) Initial forward procurement. Notwithstanding
anything to the contrary in this Section, the Agency shall
within the timeframes set forth in this paragraph (2)
procure not less than 1,500 megawatts of energy storage
resources
(A) Schedule and timing. The Agency shall
undertake each of the following steps not later than

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the following number of days after the effective date
of this amendatory Act of the 104rd General Assembly:
(i) Within 15 days, the procurement
administrator, in consultation with the electric
utilities, the Commission, and representatives of
two national or regional organizations
representing the interests of the storage industry
appointed by the Agency shall negotiate a standard
contract. If the procurement administrator cannot
reach agreement with the electric utilities or the
representatives of the storage industry, as to the
contract terms and conditions, the procurement
administrator must notify the Commission of any
disputed terms and the Commission shall resolve
the dispute;
(ii) Not later than August 26, 2025, the
procurement administrator shall close any period
available to submit price and quantity bids and
open sealed bids; and
(iii) the Commission, the procurement monitor,
the procurement administrator, and utilities shall
follow the processes and timelines set out in
subsections (f) and (g) of Section 16-111.5 of the
Public Utilities Act.
(B) For the purposes of this initial forward
procurement, the Agency shall procure energy storage

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resources totaling 1,500 megawatts for projects
committed to reaching commercial operation date on or
before December 31, 2029, subject to extension for
delay due to interconnection of the energy storage
system, delay in obtaining permits necessary to build
or operate the energy storage system, or other project
delays not primarily caused by the winning bidder or
other circumstances in the discretion of the Agency.
The Agency shall endeavor to select bids in this
initial forward procurement such that:
(i) approximately 750 megawatts are
interconnected to Midcontinent ISO, Inc.;
(ii) approximately 750 megawatts are
interconnected to PJM Interconnection, LLC Of the
750 megawatts procured under this subparagraph
(ii), at least 150 megawatts shall be located
within a city with population of more than
2,000,000 as of the effective date of the
Amendatory Act of the 104th General Assembly and
interconnected with PJM Interconnection, LLC.
(iii) If the Agency does not receive
sufficient cost-effective bids to achieve any of
the targets in this paragraph (2), the Agency
shall accept other cost-effective bids without
regard to the limitations in items (i) and (ii) of
this subparagraph (B). If, following the action

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described in the preceding sentence, the Agency
has procured less than 1,000 MW of energy storage
systems, the Agency shall repeat the steps set out
in subparagraph (A) of this paragraph (2),
provided that the Agency shall also take comment
regarding calculation of the benchmark. If,
following the process described in the preceding
sentence, the Agency has still not procured 1,500
MW of energy storage systems, the Agency shall
procure the uncontracted capacity in its next
procurement authorized under this Section.
(iv) The Agency shall require bidders to
demonstrate experience bringing utility-scale
energy storage facilities to commercial readiness.
(C) For the purposes of this initial forward
procurement only, the Agency shall require bidders to
have achieved the following interconnection milestones
unless approved under surplus interconnection service
from MISO or PJM: (i) for projects interconnected to
MISO, projects must have received a system impact
study; and (ii) for projects interconnected to PJM,
projects that have received a Phase 2 study.
(D) Notwithstanding anything to the contrary, the
requirements of subsections (d), (h), (j), (k), (l),
and (m) shall apply to this initial forward
procurement. In addition, each bidder shall

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demonstrate binding site control (including an option
to lease or purchase) sufficient for the associated
energy storage device or devices.
(c) The Agency shall select bids based on the bid price
when compared with equal energy storage duration and
interconnected to the same independent system operator or
regional transmission organization, and may give consideration
to project viability and developer experience. For the
purposes of this subsection:
(1) For indexed energy storage credit procurements,
the purchase price of the indexed energy storage credit
payment shall be calculated for each day. The payment per
energy storage credit shall be equal to the difference
resulting from subtracting from the energy storage strike
price the sum of the daily energy volatility index and the
reference capacity price for that day. If this difference
results in a positive number, the electric utility shall
owe the seller this amount multiplied by the number of
indexed energy storage credits produced on the relevant
day. If this difference results in a negative number, the
settlement shall be zero. The parties shall cash settle
every month, summing up all settlements for the prior
month.
(2) For tolling agreements, the purchase price shall
be the tolling rate as bid by the winning bidder.
(3) For pricing structures that are neither indexed

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credits nor tolling agreements, the Agency, after
consideration of feedback from potential bidders and in
consideration of financiability, shall develop
methodologies for pricing structure and bidding
procedures.
For the purposes of this subsection:
"Developer experience" means the experience of a bidder or
its affiliates assessed by the Agency, including based on
quantity of energy projects brought to commercial operation,
quantity of energy projects under ownership, and awards of
incentive contracts, including under any program or
procurement administered by the Agency.
"Project viability" means an assessment by the Agency, for
the purposes of bid evaluation, of the project's potential to
reach commercial operation as assessed by standards developed
by the Agency regarding permitting milestones, interconnection
milestones, and site control milestones.
(d) All procurements under this Section shall comply with
the geographic requirements in subparagraph (I) of paragraph
(1) of subsection (c) of Section 1-75 and shall follow the
procurement processes and procedures described in this Section
and Section 16-111.5 of the Public Utilities Act, to the
extent practicable, and these processes and procedures may be
expedited to accommodate the schedule established by this
Section. The Agency shall require all bidders to pay to the
Agency a nonrefundable deposit of $10,000 per bid. Bidders

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shall also demonstrate experience developing commercial
readiness. The winning bidders shall comply with the
prevailing wage requirements in subparagraph (Q) of paragraph
(1) of subsection (c) of Section 1-75 and the equity
accountability system requirements in subsection (c-10) of
Section 1-75. As used in this subsection (d), "developing to
commercial readiness" means having notice to proceed, owning,
or operating energy facilities with a combined nameplate
capacity of at least 100 megawatts.
(e) No later than December 31, 2026, and every 2 years
thereafter, the Agency shall conduct an analysis to determine
whether the contracted quantity of energy storage in energy
storage capacity and energy storage duration is sufficient to
support the State's renewable energy standards and carbon
emission standards. To conduct the analysis, the Agency shall
retain an independent consultant with experience in wholesale
electric system modeling in PJM and MISO and may seek the
support of the United States Department of Energy and National
Labs to conduct its analysis. The independent consultant shall
use a production cost model, capacity expansion model, or
similar comprehensive analysis of the electricity systems and
shall provide opportunities for stakeholders to provide
feedback on the scope, inputs, and assumptions used in the
analysis. The Agency is authorized to collect costs for
conducting the analysis from electric utilities. The electric
utilities are authorized to recover the cost of the analysis

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as part of the recovery of the cost of energy storage credits,
as authorized in this Section and Section 16-108 of the Public
Utilities Act. If the Agency determines that the need for
energy storage capacity or energy storage duration is greater
than the energy storage credit target in this Section, the
Agency shall establish, and the Commission shall approve, new
energy storage credit targets to meet the identified need. If
the Agency determines that deployment of energy storage beyond
2030 will not be achieved through wholesale market prices and
other energy storage programs established by the State, the
Agency shall establish additional targets for years beyond
2030.
(f) The Agency shall include in the long-term procurement
plan the energy storage duration of energy storage systems
from which the Agency shall procure energy storage credits.
Informed by the analysis described in subsection (e), when
available, the Agency shall designate the energy storage
duration or durations and the amount of energy storage
capacity at each duration from which the Agency intends to
procure energy storage credits. The long-term procurement plan
shall further propose allocation of procurements between
indexed credits and tolling agreements, taking into
consideration factors including timely commercial operation of
storage resources.
(g) The Agency shall identify in the long-term procurement
plan the regional transmission organization or independent

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system operator to which energy storage systems shall be
interconnected in order to be eligible to offer a strike price
for energy storage credits. For all solicitations prior to the
delivery year 2028, the Agency shall strive to procure at
least 70% of energy storage credits from energy storage
systems interconnected to MISO, and at least 10% of energy
storage credits from energy storage systems located within a
city with population of more than 1,000,000 people and
interconnected to PJM Interconnection, LLC. For solicitations
in the delivery year 2028 and thereafter, and informed by the
analysis described in subsection (e), the Agency shall
designate the regional transmission organization or
independent system operator to which energy storage systems
shall be interconnected in order to be eligible to offer a
strike price for energy storage credits. Following
solicitation and receipt of feedback from stakeholders
including potential bidders, the Agency shall propose in the
long-term procurement plan key terms and conditions of the
standard contracts for indexed credit and tolling agreements.
The key terms shall be designed to ensure the agreements are
financeable and to incentivize development.
(h) The Agency shall procure cost-effective energy storage
credits in at least the amounts identified in subsection (a).
The procurement administrator shall establish confidential
price benchmarks based on publicly available data on regional
technology costs. Confidential benchmarks shall be developed

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by the procurement administrator, in consultation with
Commission staff, Agency staff, and the procurement monitor,
and shall be subject to Commission review and approval.
Benchmarks shall reflect development, financing, and related
costs resulting from requirements imposed through other
provisions of State law. As used in this subsection (h), "cost
effective" means that the energy storage credit strike price
does not exceed confidential benchmarks.
(i) When developing each storage procurement plan, upon
solicitation from stakeholders, the Agency shall consider
additional procurement approaches that would result in the
electric utilities contracting for energy storage to achieve
the requirements in subsection (a).
(j) For energy storage resources procured under this
Section, the bidders or the owner's engineering, procurement,
and construction contractor, of the energy storage resources
have entered, or commit to enter, into a project labor
agreement for the construction of the energy storage resource
consistent with subsection (j) and certify that not less than
the prevailing wage, as determined by the Illinois Prevailing
Wage Act, was or will be paid to employees who are engaged in
construction activities associated with the energy storage
resource consistent with subsection (j). The project labor
agreement shall be filed with 21 the Director in accordance
with procedures established by the Agency through its storage
procurement plan. Any information submitted to the Agency

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under this subsection shall be considered commercially
sensitive information. At a minimum, the project labor
agreement must provide the names, addresses, and occupations
of the owner of the plant and the individuals representing the
labor organization employees participating in the project
labor agreement in accordance with the Project Labor
Agreements Act. The agreement must also specify the terms and
conditions as described in this Act.
(k) In order to promote the competitive development of
energy storage system in furtherance of the State's interest
in the health, safety, and welfare of its residents, storage
credits shall not be eligible to be selected under this
Section if they are sourced from an energy storage system
whose costs were being recovered through rates regulated by
this State or any other state or states on or after January 1,
2017. Each contract executed to purchase storage credits under
this Section shall provide for the contract's termination if
the costs of the energy storage system supplying the storage
credits subsequently begin to be recovered through rates
regulated by this State or any other state or states. Each
contract shall provide that, in the event the costs of the
energy storage system supplying the storage credits
subsequently begin to be recovered through rates regulated by
this State or any other state or states, the supplier of the
credits must return 110% of all payments received under the
contract. Amounts returned under the requirements of this

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subsection shall be refunded to ratepayers. No entity shall be
permitted to bid unless it certifies to the Agency that it is
not an electric utility, as defined in Section 16-102 of the
Public Utilities Act, serving more than 10,000 customers in
the State.
(l) The Agency shall require that as a prerequisite to
payment for any storage credits that the winning bidder
provide the Agency or its designee a copy of the
interconnection agreement under which the applicable energy
storage system is connected to the transmission or
distribution system.
(m) To ensure the successful development of new energy
storage systems for procurements under this Section, a winning
bidder or the current seller under contract countersigned by
an electric utility counterparty may petition the Commission
to revise the terms in the contract. Prior to such petition,
upon request by the winning bidder or seller, the Agency shall
negotiate directly with the winning bidder or seller. If
following the direct negotiations, the Agency and the winning
bidder reach an agreement on amended terms or a strike price
and the Agency finds that the amended terms or strike price
reflect a change in circumstances since the date of the bid
based on circumstances unforeseeable at the time of the bid,
upon petition by the winning bidder or current seller, then
the Commission shall issue an order directing the utility
counterparty to execute a form amendment drafted by the Agency

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with the revised terms or the strike price. The Agency shall
provide the amendment to the utility within 15 business days
after the Commission's order and the utility buyer shall
execute the amendment not more than 7 calendar days after
delivery by the Agency. The Agency shall develop the form
amendment following comment by interested parties.
(20 ILCS 3855/1-94 new)
Sec. 1-94. Firm energy resource procurement plan. The
Agency is authorized to develop and implement a firm energy
resource procurement plan for new resources, including
initiating proceedings and conducting competitive
solicitations to deploy new long-duration and multi-day energy
storage. The procurement plan shall ensure regular procurement
opportunities to deploy new long-duration and multi-day energy
storage resources by 2030 and shall ensure stable, competitive
resource development at a pace needed to ensure grid
reliability and resilience during atypical or extreme grid
conditions that may occur at least once in 20 years while
meeting the emissions requirements of Section 9.15 of the
Environmental Protection Act. The Agency's plan shall ensure
that a minimum of 4 new long-duration or multi-day energy
storage resources, each with a rated capacity greater than 20
megawatts, shall be deployed or contracted by the end of
delivery year 2026. Within one year after the effective date
of this amendatory Act of the 104th General Assembly, the

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Agency shall develop a firm energy resource procurement plan
in accordance with this Section and Section 16-111.5 of the 1
Public Utilities Act.
Section 10. The Public Utilities Act is amended by
changing Sections 3-105, 16-102, 16-107.5, 16-107.6, 16-108,
16-111.5, and 16-115 and by adding Sections 8-513, 16-107.8,
16-107.9, 16-107.10, 16-107.11, and 16-136 and Article XXIII
as follows:
(220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)
Sec. 3-105. Public utility.
(a) "Public utility" means and includes, except where
otherwise expressly provided in this Section, every
corporation, company, limited liability company, association,
joint stock company or association, firm, partnership or
individual, their lessees, trustees, or receivers appointed by
any court whatsoever that owns, controls, operates or manages,
within this State, directly or indirectly, for public use, any
plant, equipment or property used or to be used for or in
connection with, or owns or controls any franchise, license,
permit or right to engage in:
(1) the production, storage, transmission, sale,
delivery or furnishing of heat, cold, power, electricity,
water, or light, except when used solely for
communications purposes;

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(2) the disposal of sewerage; or
(3) the conveyance of oil or gas by pipe line.
(b) "Public utility" does not include, however:
(1) public utilities that are owned and operated by
any political subdivision, public institution of higher
education or municipal corporation of this State, or
public utilities that are owned by such political
subdivision, public institution of higher education, or
municipal corporation and operated by any of its lessees
or operating agents;
(2) water companies which are purely mutual concerns,
having no rates or charges for services, but paying the
operating expenses by assessment upon the members of such
a company and no other person;
(3) electric cooperatives as defined in Section 3-119;
(4) the following natural gas cooperatives:
(A) residential natural gas cooperatives that are
not-for-profit corporations established for the
purpose of administering and operating, on a
cooperative basis, the furnishing of natural gas to
residences for the benefit of their members who are
residential consumers of natural gas. For entities
qualifying as residential natural gas cooperatives and
recognized by the Illinois Commerce Commission as
such, the State shall guarantee legally binding
contracts entered into by residential natural gas

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cooperatives for the express purpose of acquiring
natural gas supplies for their members. The Illinois
Commerce Commission shall establish rules and
regulations providing for such guarantees. The total
liability of the State in providing all such
guarantees shall not at any time exceed $1,000,000,
nor shall the State provide such a guarantee to a
residential natural gas cooperative for more than 3
consecutive years; and
(B) natural gas cooperatives that are
not-for-profit corporations operated for the purpose
of administering, on a cooperative basis, the
furnishing of natural gas for the benefit of their
members and that, prior to 90 days after the effective
date of this amendatory Act of the 94th General
Assembly, either had acquired or had entered into an
asset purchase agreement to acquire all or
substantially all of the operating assets of a public
utility or natural gas cooperative with the intention
of operating those assets as a natural gas
cooperative;
(5) sewage disposal companies which provide sewage
disposal services on a mutual basis without establishing
rates or charges for services, but paying the operating
expenses by assessment upon the members of the company and
no others;

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(6) (blank);
(7) cogeneration facilities, small power production
facilities, and other qualifying facilities, as defined in
the Public Utility Regulatory Policies Act and regulations
promulgated thereunder, except to the extent State
regulatory jurisdiction and action is required or
authorized by federal law, regulations, regulatory
decisions or the decisions of federal or State courts of
competent jurisdiction;
(8) the ownership or operation of a facility that
sells compressed natural gas at retail to the public for
use only as a motor vehicle fuel and the selling of
compressed natural gas at retail to the public for use
only as a motor vehicle fuel;
(9) alternative retail electric suppliers as defined
in Article XVI; and
(10) the Illinois Power Agency.
(11) transmission co-location customers or
distribution co-location customers as defined in Article
XVI;
(c) An entity that furnishes the service of charging
electric vehicles does not and shall not be deemed to sell
electricity and is not and shall not be deemed a public utility
notwithstanding the basis on which the service is provided or
billed. If, however, the entity is otherwise deemed a public
utility under this Act, or is otherwise subject to regulation

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under this Act, then that entity is not exempt from and remains
subject to the otherwise applicable provisions of this Act.
The installation, maintenance, and repair of an electric
vehicle charging station shall comply with the requirements of
subsection (a) of Section 16-128 and Section 16-128A of this
Act.
For purposes of this subsection, the term "electric
vehicles" has the meaning ascribed to that term in Section 10
of the Electric Vehicle Act.
(Source: P.A. 97-1128, eff. 8-28-12.)
(220 ILCS 5/8-513 new)
Sec. 8-513. Staffing adequacy.
(a) The General Assembly finds and declares that devotion
of adequate resources, including human resources and technical
resources, to interconnection of electric generation to the
electric distribution grid and transmission grid are necessary
to meeting the State's renewable energy goals, including the
goals set out in Section 1-75 of the Illinois Power Agency Act.
The General Assembly further finds that insufficient human
resources or inadequate systems, recordkeeping, or technical
ability to interconnection by electric utilities risks delays,
mistakes, and disputes under applicable interconnection
procedures.
(b) Each electric utility, as defined in Section 16-102,
shall demonstrate sufficient resources devoted to

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interconnection.
(c) The Commission shall review in a contested proceeding
the compliance of each electric utility with the electric
utility's individual compliance with obligations under
subsection (b). If the Commission, after notice and hearing,
finds that an electric utility did not meet its obligations
under subsection (b), or is at risk of not meeting such
obligations in the future, the Commission may require the
electric utility to submit a compliance plan to meet such
obligations. The Commission shall approve or approve with
modifications a compliance plan if the Commission finds that
the compliance plan is likely to ensure compliance with the
electric utility's obligations under subsection (b), or likely
with modifications to ensure compliance.
(d) As used in this Section:
"Interconnection" means the steps to interconnect
electric generation fueled by renewable resources, energy
storage, or a combination of generation fueled by
renewable resources and storage under procedures set out
in this Act, rules adopted by the Commission, PJM
Interconnection, Inc. or its successor, or Midcontinent
Independent System Operator or its successor.
"Resources" means the combination of employees,
independent contractors, vendors, and systems and software
that directly support interconnection but shall not
include the transformers, reclosers, line, and similar

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physical assets used to connect or upgrade the
distribution or transmission grids.
(220 ILCS 5/16-102)
Sec. 16-102. Definitions. For the purposes of this Article
the following terms shall be defined as set forth in this
Section.
"Alternative retail electric supplier" means every person,
cooperative, corporation, municipal corporation, company,
association, joint stock company or association, firm,
partnership, individual, or other entity, their lessees,
trustees, or receivers appointed by any court whatsoever, that
offers electric power or energy for sale, lease or in exchange
for other value received to one or more retail customers, or
that engages in the delivery or furnishing of electric power
or energy to such retail customers, and shall include, without
limitation, resellers, aggregators and power marketers, but
shall not include (i) electric utilities (or any agent of the
electric utility to the extent the electric utility provides
tariffed services to retail customers through that agent),
(ii) any electric cooperative or municipal system as defined
in Section 17-100 to the extent that the electric cooperative
or municipal system is serving retail customers within any
area in which it is or would be entitled to provide service
under the law in effect immediately prior to the effective
date of this amendatory Act of 1997, (iii) a public utility

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that is owned and operated by any public institution of higher
education of this State, or a public utility that is owned by
such public institution of higher education and operated by
any of its lessees or operating agents, within any area in
which it is or would be entitled to provide service under the
law in effect immediately prior to the effective date of this
amendatory Act of 1997, (iv) a retail customer to the extent
that customer obtains its electric power and energy from that
customer's own cogeneration or self-generation facilities, (v)
an entity that owns, operates, sells, or arranges for the
installation of a customer's own cogeneration or
self-generation facilities, but only to the extent the entity
is engaged in owning, selling or arranging for the
installation of such facility, or operating the facility on
behalf of such customer, provided however that any such third
party owner or operator of a facility built after January 1,
1999, complies with the labor provisions of Section 16-128(a)
as though such third party were an alternative retail electric
supplier, or (vi) an industrial or manufacturing customer that
owns its own distribution facilities, to the extent that the
customer provides service from that distribution system to a
third-party contractor located on the customer's premises that
is integrally and predominantly engaged in the customer's
industrial or manufacturing process; provided, that if the
industrial or manufacturing customer has elected delivery
services, the customer shall pay transition charges applicable

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to the electric power and energy consumed by the third-party
contractor unless such charges are otherwise paid by the third
party contractor, which shall be calculated based on the usage
of, and the base rates or the contract rates applicable to, the
third-party contractor in accordance with Section 16-102. A
transmission co-location customer or a distribution
co-location customer shall be an alternative retail electric
supplier.
An entity that furnishes the service of charging electric
vehicles does not and shall not be deemed to sell electricity
and is not and shall not be deemed an alternative retail
electric supplier, and is not subject to regulation as such
under this Act notwithstanding the basis on which the service
is provided or billed. If, however, the entity is otherwise
deemed an alternative retail electric supplier under this Act,
or is otherwise subject to regulation under this Act, then
that entity is not exempt from and remains subject to the
otherwise applicable provisions of this Act. The installation,
maintenance, and repair of an electric vehicle charging
station shall comply with the requirements of subsection (a)
of Section 16-128 and Section 16-128A of this Act.
For purposes of this Section, the term "electric vehicles"
has the meaning ascribed to that term in Section 10 of the
Electric Vehicle Act.
"Base rates" means the rates for those tariffed services
that the electric utility is required to offer pursuant to

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subsection (a) of Section 16-103 and that were identified in a
rate order for collection of the electric utility's base rate
revenue requirement, excluding (i) separate automatic rate
adjustment riders then in effect, (ii) special or negotiated
contract rates, (iii) delivery services tariffs filed pursuant
to Section 16-108, (iv) real-time pricing, or (v) tariffs that
were in effect prior to October 1, 1996 and that based charges
for services on an index or average of other utilities'
charges, but including (vi) any subsequent redesign of such
rates for tariffed services that is authorized by the
Commission after notice and hearing.
"Competitive service" includes (i) any service that has
been declared to be competitive pursuant to Section 16-113 of
this Act, (ii) contract service, and (iii) services, other
than tariffed services, that are related to, but not necessary
for, the provision of electric power and energy or delivery
services.
"Contract service" means (1) services, including the
provision of electric power and energy or other services, that
are provided by mutual agreement between an electric utility
and a retail customer that is located in the electric
utility's service area, provided that, delivery services shall
not be a contract service until such services are declared
competitive pursuant to Section 16-113; and also means (2) the
provision of electric power and energy by an electric utility
to retail customers outside the electric utility's service

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area pursuant to Section 16-116. Provided, however, contract
service does not include electric utility services provided
pursuant to (i) contracts that retail customers are required
to execute as a condition of receiving tariffed services, or
(ii) special or negotiated rate contracts for electric utility
services that were entered into between an electric utility
and a retail customer prior to the effective date of this
amendatory Act of 1997 and filed with the Commission.
"Delivery services" means those services provided by the
electric utility that are necessary in order for the
transmission and distribution systems to function so that
retail customers located in the electric utility's service
area can receive electric power and energy from suppliers
other than the electric utility, and shall include, without
limitation, standard metering and billing services.
"Distribution co-location customer" means an end-user of
electric power and energy and associated generation and as
applicable energy storage that:
(1) can demonstrate projected onsite demand of at
least 10 megawatts alternating current;
(2) the end user of electric power and energy is
electrically connected to (i) one or more generators that
are each renewable energy resources, as defined in Section
1-10 of the Illinois Power Agency Act, with a cumulative
nameplate capacity of at least 5 megawatts alternating
current; or (ii) one or more generators that are each

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renewable energy resources, as defined in Section 1-10 of
the Illinois Power Agency Act, and energy storage devices,
with a cumulative total nameplate capacity of at least 5
megawatts alternating current; and
(3) is interconnected with the distribution system of
an electric utility;
For the purposes of this definition, the generator(s), the
energy storage, and load(s) need not be the same or affiliated
entities but must at minimum have a contractual relationship
as further defined in Section 16-115 of this Act.
"Electric utility" means a public utility, as defined in
Section 3-105 of this Act, that has a franchise, license,
permit or right to furnish or sell electricity to retail
customers within a service area.
"Mandatory transition period" means the period from the
effective date of this amendatory Act of 1997 through January
1, 2007.
"Municipal system" shall have the meaning set forth in
Section 17-100.
"Real-time pricing" means tariffed retail charges for
delivered electric power and energy that vary hour-to-hour and
are determined from wholesale market prices using a
methodology approved by the Illinois Commerce Commission.
"Retail customer" means a single entity using electric
power or energy at a single premises and that (A) either (i) is
receiving or is eligible to receive tariffed services from an

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electric utility, or (ii) that is served by a municipal system
or electric cooperative within any area in which the municipal
system or electric cooperative is or would be entitled to
provide service under the law in effect immediately prior to
the effective date of this amendatory Act of 1997, or (B) an
entity which on the effective date of this Act was receiving
electric service from a public utility and (i) was engaged in
the practice of resale and redistribution of such electricity
within a building prior to January 2, 1957, or (ii) was
providing lighting services to tenants in a multi-occupancy
building, but only to the extent such resale, redistribution
or lighting service is authorized by the electric utility's
tariffs that were on file with the Commission on the effective
date of this Act. "Retail Customer" shall not include any
co-location customer.
"Service area" means (i) the geographic area within which
an electric utility was lawfully entitled to provide electric
power and energy to retail customers as of the effective date
of this amendatory Act of 1997, and includes (ii) the location
of any retail customer to which the electric utility was
lawfully providing electric utility services on such effective
date.
"Small commercial retail customer" means those
nonresidential retail customers of an electric utility
consuming 15,000 kilowatt-hours or less of electricity
annually in its service area.

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"Tariffed service" means services provided to retail
customers by an electric utility as defined by its rates on
file with the Commission pursuant to the provisions of Article
IX of this Act, but shall not include competitive services.
"Transition charge" means a charge expressed in cents per
kilowatt-hour that is calculated for a customer or class of
customers as follows for each year in which an electric
utility is entitled to recover transition charges as provided
in Section 16-108:
(1) the amount of revenue that an electric utility
would receive from the retail customer or customers if it
were serving such customers' electric power and energy
requirements as a tariffed service based on (A) all of the
customers' actual usage during the 3 years ending 90 days
prior to the date on which such customers were first
eligible for delivery services pursuant to Section 16-104,
and (B) on (i) the base rates in effect on October 1, 1996
(adjusted for the reductions required by subsection (b) of
Section 16-111, for any reduction resulting from a rate
decrease under Section 16-101(b), for any restatement of
base rates made in conjunction with an elimination of the
fuel adjustment clause pursuant to subsection (b), (d), or
(f) of Section 9-220 and for any removal of
decommissioning costs from base rates pursuant to Section
16-114) and any separate automatic rate adjustment riders
(other than a decommissioning rate as defined in Section

HB3758 - 245 - LRB104 12225 JDS 22331 b
16-114) under which the customers were receiving or, had
they been customers, would have received electric power
and energy from the electric utility during the year
immediately preceding the date on which such customers
were first eligible for delivery service pursuant to
Section 16-104, or (ii) to the extent applicable, any
contract rates, including contracts or rates for
consolidated or aggregated billing, under which such
customers were receiving electric power and energy from
the electric utility during such year;
(2) less the amount of revenue, other than revenue
from transition charges and decommissioning rates, that
the electric utility would receive from such retail
customers for delivery services provided by the electric
utility, assuming such customers were taking delivery
services for all of their usage, based on the delivery
services tariffs in effect during the year for which the
transition charge is being calculated and on the usage
identified in paragraph (1);
(3) less the market value for the electric power and
energy that the electric utility would have used to supply
all of such customers' electric power and energy
requirements, as a tariffed service, based on the usage
identified in paragraph (1), with such market value
determined in accordance with Section 16-112 of this Act;
(4) less the following amount which represents the

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amount to be attributed to new revenue sources and cost
reductions by the electric utility through the end of the
period for which transition costs are recovered pursuant
to Section 16-108, referred to in this Article XVI as a
"mitigation factor":
(A) for nonresidential retail customers, an amount
equal to the greater of (i) 0.5 cents per
kilowatt-hour during the period October 1, 1999
through December 31, 2004, 0.6 cents per kilowatt-hour
in calendar year 2005, and 0.9 cents per kilowatt-hour
in calendar year 2006, multiplied in each year by the
usage identified in paragraph (1), or (ii) an amount
equal to the following percentages of the amount
produced by applying the applicable base rates
(adjusted as described in subparagraph (1)(B)) or
contract rate to the usage identified in paragraph
(1): 8% for the period October 1, 1999 through
December 31, 2002, 10% in calendar years 2003 and
2004, 11% in calendar year 2005 and 12% in calendar
year 2006; and
(B) for residential retail customers, an amount
equal to the following percentages of the amount
produced by applying the base rates in effect on
October 1, 1996 (adjusted as described in subparagraph
(1)(B)) to the usage identified in paragraph (1): (i)
6% from May 1, 2002 through December 31, 2002, (ii) 7%

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in calendar years 2003 and 2004, (iii) 8% in calendar
year 2005, and (iv) 10% in calendar year 2006;
(5) divided by the usage of such customers identified
in paragraph (1),
provided that the transition charge shall never be less than
zero.
"Transmission co-location customer" means an end-user of
electric power and energy and associated generation and as
applicable energy storage that:
(1) can demonstrate projected onsite demand of at
least 50 megawatts alternating current;
(2) the end-user of electric power and energy is
electrically connected to (i) one or more generators that
are each renewable energy resources, as defined in Section
1-10 of the Illinois Power Agency Act, with a cumulative
nameplate capacity of at least 50 megawatts alternating
current; or (ii) one or more generators that are each
renewable energy resources, as defined in Section 1-10 of
the Illinois Power Agency Act, and energy storage devices,
with a cumulative total nameplate capacity of at least 50
megawatts alternating current;
(3) is interconnected to PJM Interconnection, LLC or
Midcontinent Independent System Operator, Inc.;
(4) is not interconnected to the distribution system
of an electric utility, a municipal system, or an electric
cooperative; and

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(5) has received requisite authority from the Federal
Energy Regulatory Commission, PJM Interconnection, LLC or
Midcontinent Independent System Operator, Inc. as a
load-serving entity.
For the purposes of this definition, the generator(s), the
energy storage, and load(s) need not be the same or affiliated
entities but must at minimum have a contractual relationship
as further defined in Section 16-115 of this Act.
"Unbundled service" means a component or constituent part
of a tariffed service which the electric utility subsequently
offers separately to its customers.
(Source: P.A. 97-1128, eff. 8-28-12.)
(220 ILCS 5/16-107.5)
Sec. 16-107.5. Net electricity metering.
(a) The General Assembly finds and declares that a program
to provide net electricity metering, as defined in this
Section, for eligible customers can encourage private
investment in renewable energy resources, stimulate economic
growth, enhance the continued diversification of Illinois'
energy resource mix, and protect the Illinois environment.
Further, to achieve the goals of this Act that robust options
for customer-site distributed generation continue to thrive in
Illinois, the General Assembly finds that a predictable
transition must be ensured for customers between full net
metering at the retail electricity rate to the distribution

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generation rebate described in Section 16-107.6.
(b) As used in this Section, (i) "community renewable
generation project" shall have the meaning set forth in
Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
customer" means a retail customer that owns, hosts, or
operates, including any third-party owned systems, a solar,
wind, or other eligible renewable electrical generating
facility that is located on the customer's premises or
customer's side of the billing meter and is intended primarily
to offset the customer's own current or future electrical
requirements; (iii) "electricity provider" means an electric
utility or alternative retail electric supplier; (iv)
"eligible renewable electrical generating facility" means a
generator, which may include the co-location of an energy
storage system, that is interconnected under rules adopted by
the Commission and is powered by solar electric energy, wind,
dedicated crops grown for electricity generation, agricultural
residues, untreated and unadulterated wood waste, livestock
manure, anaerobic digestion of livestock or food processing
waste, fuel cells or microturbines powered by renewable fuels,
or hydroelectric energy; (v) "net electricity metering" (or
"net metering") means the measurement, during the billing
period applicable to an eligible customer, of the net amount
of electricity supplied by an electricity provider to the
customer or provided to the electricity provider by the
customer or subscriber; (vi) "subscriber" shall have the

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meaning as set forth in Section 1-10 of the Illinois Power
Agency Act; (vii) "subscription" shall have the meaning set
forth in Section 1-10 of the Illinois Power Agency Act; (viii)
"energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter; and (ix) "future electrical requirements" means modeled
electrical requirements upon occupation of a new or vacant
property, and other reasonable expectations of future
electrical use, as well as, for occupied properties, a
reasonable approximation of the annual load of 2 electric
vehicles and, for non-electric heating customers, a reasonable
approximation of the incremental electric load associated with
fuel switching. The approximations shall be applied to the
appropriate net metering tariff and do not need to be unique to
each individual eligible customer. The utility shall submit
these approximations to the Commission for review,
modification, and approval.
(c) A net metering facility shall be equipped with
metering equipment that can measure the flow of electricity in
both directions at the same rate.
(1) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113

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

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

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supplied to and used by the customer as provided in
subsection (e-5) of this Section.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing
period, the electricity provider supplying that customer
shall apply a 1:1 kilowatt-hour credit to a subsequent
bill for service to the customer for the net electricity
supplied to the electricity provider. The electricity
provider shall continue to carry over any excess
kilowatt-hour credits earned and apply those credits to
subsequent billing periods to offset any
customer-generator consumption in those billing periods
until all credits are used or until the end of the
annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates
service with the electricity provider prior to the end of
the year or the annualized period, any remaining credits
in the customer's account shall expire.
(d-5) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery service

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is provided and measured on a kilowatt-hour basis and electric
supply service is provided based on hourly pricing or
time-of-use rates in the following manner:
(1) If the amount of electricity used by the customer
during any hourly period or time-of-use period exceeds the
amount of electricity produced by the customer, the
electricity provider shall charge the customer for the net
electricity supplied to and used by the customer according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer.
(2) If the amount of electricity produced by a
customer during any hourly period or time-of-use period
exceeds the amount of electricity used by the customer
during that hourly period or time-of-use period, the
energy provider shall apply a credit for the net
kilowatt-hours produced in such period. The credit shall
consist of an energy credit and a delivery service credit.
The energy credit shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for kilowatt-hour energy sales during that same
hourly period or time-of-use period. The delivery credit
shall be equal to the net kilowatt-hours produced in such
hourly period or time-of-use period times a credit that
reflects all kilowatt-hour based charges in the customer's
electric service rate, excluding energy charges.

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(e) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
whose electric service has not been declared competitive
pursuant to Section 16-113 of this Act as of July 1, 2011 and
whose electric delivery service is provided and measured on a
kilowatt demand basis and electric supply service is not
provided based on hourly pricing in the following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of
electricity produced by the customer, then the electricity
provider shall charge the customer for the net electricity
supplied to and used by the customer as provided in
subsection (e-5) of this Section. The customer shall
remain responsible for all taxes, fees, and utility
delivery charges that would otherwise be applicable to the
net amount of electricity used by the customer.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing
period, then the electricity provider supplying that
customer shall apply a 1:1 kilowatt-hour credit that
reflects the kilowatt-hour based charges in the customer's
electric service rate to a subsequent bill for service to
the customer for the net electricity supplied to the
electricity provider. The electricity provider shall
continue to carry over any excess kilowatt-hour credits

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earned and apply those credits to subsequent billing
periods to offset any customer-generator consumption in
those billing periods until all credits are used or until
the end of the annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates
service with the electricity provider prior to the end of
the year or the annualized period, any remaining credits
in the customer's account shall expire.
(e-5) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect to
rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged if not
a net metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements not
specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or other
requirement would apply to other similarly situated customers
who are not net metering customers. The customer will remain
responsible for all taxes, fees, and utility delivery charges
that would otherwise be applicable to the net amount of
electricity used by the customer. Subsections (c) through (e)
of this Section shall not be construed to prevent an

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arms-length agreement between an electricity provider and an
eligible customer that sets forth different prices, terms, and
conditions for the provision of net metering service,
including, but not limited to, the provision of the
appropriate metering equipment for non-residential customers.
(f) Notwithstanding the requirements of subsections (c)
through (e-5) of this Section, an electricity provider must
require dual-channel metering for customers operating eligible
renewable electrical generating facilities to whom the
provisions of neither subsection (d), (d-5), nor (e) of this
Section apply. In such cases, electricity charges and credits
shall be determined as follows:
(1) The electricity provider shall assess and the
customer remains responsible for all taxes, fees, and
utility delivery charges that would otherwise be
applicable to the gross amount of kilowatt-hours supplied
to the eligible customer by the electricity provider.
(2) Each month that service is supplied by means of
dual-channel metering, the electricity provider shall
compensate the eligible customer for any excess
kilowatt-hour credits at the electricity provider's
avoided cost of electricity supply over the monthly period
or as otherwise specified by the terms of a power-purchase
agreement negotiated between the customer and electricity
provider.
(3) For all eligible net metering customers taking

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service from an electricity provider under contracts or
tariffs employing hourly or time-of-use rates, any monthly
consumption of electricity shall be calculated according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer. When those same
customer-generators are net generators during any discrete
hourly or time-of-use period, the net kilowatt-hours
produced shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for retail kilowatt-hour sales during that same
time-of-use period.
(g) For purposes of federal and State laws providing
renewable energy credits or greenhouse gas credits, the
eligible customer shall be treated as owning and having title
to the renewable energy attributes, renewable energy credits,
and greenhouse gas emission credits related to any electricity
produced by the qualified generating unit. The electricity
provider may not condition participation in a net metering
program on the signing over of a customer's renewable energy
credits; provided, however, this subsection (g) shall not be
construed to prevent an arms-length agreement between an
electricity provider and an eligible customer that sets forth
the ownership or title of the credits.
(h) Within 120 days after the effective date of this
amendatory Act of the 95th General Assembly, the Commission

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shall establish standards for net metering and, if the
Commission has not already acted on its own initiative,
standards for the interconnection of eligible renewable
generating equipment to the utility system. The
interconnection standards shall address any procedural
barriers, delays, and administrative costs associated with the
interconnection of customer-generation while ensuring the
safety and reliability of the units and the electric utility
system. The Commission shall consider the Institute of
Electrical and Electronics Engineers (IEEE) Standard 1547 and
the issues of (i) reasonable and fair fees and costs, (ii)
clear timelines for major milestones in the interconnection
process, (iii) nondiscriminatory terms of agreement, and (iv)
any best practices for interconnection of distributed
generation.
(h-5) Within 90 days after the effective date of this
amendatory Act of the 104th General Assembly amendatory Act of
the 102nd General Assembly, the Commission shall:
(1) establish an Interconnection Working Group. The
working group shall include representatives from electric
utilities, developers of renewable electric generating
facilities, other industries that regularly apply for
interconnection with the electric utilities,
representatives of distributed generation customers, the
Commission Staff, and such other stakeholders with a
substantial interest in the topics addressed by the

HB3758 - 260 - LRB104 12225 JDS 22331 b
Interconnection Working Group. The Interconnection Working
Group shall address at least the following issues:
(A) cost and best available technology for
interconnection and metering, including the
standardization and publication of standard costs;
(B) transparency, accuracy and use of the
distribution interconnection queue and hosting
capacity maps;
(C) distribution system upgrade cost avoidance
through use of advanced inverter functions;
(D) predictability of the queue management process
and enforcement of timelines;
(E) benefits and challenges associated with group
studies and cost sharing;
(F) minimum requirements for application to the
interconnection process and throughout the
interconnection process to avoid queue clogging
behavior;
(G) process and customer service for
interconnecting customers adopting distributed energy
resources, including energy storage;
(H) options for metering distributed energy
resources, including energy storage;
(I) interconnection of new technologies, including
smart inverters and energy storage;
(J) collect, share, and examine data on Level 1

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interconnection costs, including cost and type of
upgrades required for interconnection, and use this
data to inform the final standardized cost of Level 1
interconnection; and
(K) such other technical, policy, and tariff
issues related to and affecting interconnection
performance and customer service as determined by the
Interconnection Working Group.
The Commission may create subcommittees of the
Interconnection Working Group to focus on specific issues
of importance, as appropriate. The Ombudsman, on behalf of
the Interconnection Working Group, shall report to the
Commission on recommended improvements to interconnection
rules and tariffs and policies as determined by the
Interconnection Working Group at least every 6 months.
Such reports shall include consensus recommendations of
the Interconnection Working Group and, if applicable,
additional recommendations for which consensus was not
reached. The Commission shall use the report from the
Interconnection Working Group to determine whether
processes should be commenced to formally codify or
implement the recommendations;
(2) designate the Ombudsperson described in Section
23-110, or his or her designee within the Office of
Interconnection and Renewable Development, to act as the
facilitator for the Interconnection Working Group for the

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purpose of resolving create or contract for an Ombudsman
to resolve interconnection disputes through mediation or
non-binding arbitration, to the extent mediation or
non-binding arbitration is available under rules adopted
by the Commission. As the facilitator for the
Interconnection Working Group, the Ombudsperson shall
convene stakeholders to set agendas for discussions, lead
meetings, ensure notes are distributed to members, and
perform other tasks necessary to support the good-faith
advancement of discussions. The Ombudsperson Ombudsman may
be paid in full or in part through fees levied on the
initiators of the dispute; and
(3) determine a single standardized cost for Level 1
interconnections, which shall not exceed $200; .
(4) require all electric utilities to perform a system
impact and facilities study to provide a detailed
breakdown of the non-binding costs of operation and an
estimate that individually itemizes operational costs,
including equipment by type or model, labor, operation and
maintenance, engineering and design, permitting, easements
and rights-of-way, direct overhead, and indirect overhead;
(5) prohibit electric utilities from recovering from
an interconnection customer more than 125% of the
non-binding cost estimate in the system impact and
facilities study described in paragraph (4). An electric
utility with a Multi-Year Rate Plan may recover prudent

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and reasonable costs of interconnection that are not
recoverable from the interconnection customer under this
paragraph from all customers through its Multi-Year Rate
Plan;
(6) open a proceeding, not to exceed 240 days in
duration, to create a uniform standard for cost-sharing of
interconnections. As used in this paragraph, "cost-sharing
of interconnections" means a system under which an
electric utility assigns the costs of upgrades to a
distribution-voltage substation that exceeds $5,000,000
between the interconnection customer that initially causes
the upgrade and interconnection customers subsequent in
the interconnection queue, not to exceed 10 customers,
that directly benefit from the increased hosting capacity
from the upgrade, including applicants that subsequently
enter the queue;
(7) adopt rules, in addition to dispute resolution
provisions under the Commission's rules authorized by
subsection (h), as long as, upon complaint by an electric
utility, an interconnection customer, or an
interconnection applicant, the Ombudsperson, or his or her
designee, provides a recommended resolution of any dispute
within 5 business days after receiving the complaint. The
electric utility, the interconnection customer, the
interconnection applicant, or any other party authorized
to initiate dispute resolution under the Commission's

HB3758 - 264 - LRB104 12225 JDS 22331 b
rules authorized by subsection (h) may include the
Ombudsperson's recommendation in any dispute resolution.
Nothing in this paragraph prohibits the Ombudsperson from
taking part in a dispute as required by this Section or the
Commission's rules;
(8) require each electric utility to offer flexible
interconnection. An interconnection applicant may propose
flexible interconnection options and an electric utility
shall not unreasonably deny the proposal. If curtailment
is expected under the flexible interconnection option, the
electric utility shall provide an analysis of the expected
rate of curtailment, inclusive of calculations, as well as
load, generation, contingency, and system limit
assumptions used. Each study of interconnection costs with
a cost exceeding $0.30 per watt shall include an
evaluation of flexible interconnection options. As used in
this paragraph, "flexible interconnection" means active or
passive hardware, software, or other controls allowing
curtailment of distributed energy resources during grid
conditions that might otherwise impact safety or
reliability of the distribution system;
(9) require all electric utilities to accept any of
cash, letters of credit, or bonds as deposit for
construction of interconnection facilities or distribution
upgrades. Electric utilities shall also provide the option
for the electric utility to hold deposit amounts in escrow

HB3758 - 265 - LRB104 12225 JDS 22331 b
by a mutually agreed-upon third-party, with any interest
to inure to the benefit of the interconnection customer;
(10) require all electric utilities, in studying
potential interconnection of distributed energy resources,
to present at the feasibility study stage (if applicable)
a proposed scope of upgrades and non-binding cost estimate
for the customer-selected feeder as well as the
non-binding cost estimate and scope of upgrades for up to
one other selected feeder if so requested, the additional
cost of which shall be borne by the interconnection
customer. At the conclusion of the feasibility study the
interconnection customer shall be entitled to choose
between the two options presented by the electric utility,
and notwithstanding any other requirement of this Act,
rule, or tariff shall be given the opportunity to reduce
system size if doing so would preclude the need for costly
upgrades, all decisions shall be made prior to the start
of the system impact study (if applicable), after which
any further studies shall only be performed on the option
selected and no material changes to system size will be
allowed. In addition, the electric utility shall present a
separate proposed scope and non-binding cost estimate for
exceeding any distributed energy resource capacity limits
imposed by the electric utility;
(11) prohibit the electric utility from conditioning
study of an interconnection application on study, deposit,

HB3758 - 266 - LRB104 12225 JDS 22331 b
or approval of any other distributed energy resource ahead
in queue, however nothing prohibits an electric utility
from identifying contingent upgrades for applicants lower
in queue. In such case, the electric utility shall
identify the projects ahead of the applicant in the queue
to the applicant or interconnection customer;
(12) require facilities study, as defined under the
Commission's rules adopted pursuant to subsection (h), to
include analysis of required easements, including the pin
number of each parcel on which customer-acquired easements
are needed. The electric utility shall allow use of the
electric utility's easements for interconnection
facilities and distribution upgrades, including
interconnection facilities and distribution upgrades
constructed by the applicant, interconnection customer, or
a third party on their behalf;
(13) require each electric utility to provide guidance
20 to applicants lower in queue on the detailed scope,
schedule, and cost of contingent upgrades that may become
that applicant's responsibility 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 1

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contingent upgrades fall to either pay the additional 2
deposit amount or withdraw their project;
(14) require each utility to maintain a public queue
with project-specific information including nameplate
capacity, energy storage nameplate capacity, if any,
contingent upgrades, if any, and estimated non-binding
interconnection cost provided by the electric utility to
the applicant or interconnection customer. The Commission
may require additional information be provided under this
paragraph; and
(15) require each electric utility serving more than
100,000 customers on January 1, 2023, to the extent not
provided in its multi-year grid plan, to submit to the
Commission a plan to implement public dynamic hosting
capacity maps not later than January 1, 2026. For the
purposes of this paragraph, "dynamic hosting capacity
maps" means publicly-facing hosting capacity maps that are
updated in real time or not less frequently than daily,
based on information received or provided by the electric
utility.
(16) modify the Standard Agreement for Interconnection
of Distributed Energy Resources Facilities described in
Section 466.Appendix D and 467.Appendix C or their
successors to provide a clear timeline require return of
interconnection customer deposits within 30 calendar days
of termination of the interconnection agreement, provided

HB3758 - 268 - LRB104 12225 JDS 22331 b
that the electric utility shall not be required to return
deposits to the extent such deposit has already been
spent.
(17) require each electric utility serving more than
100,000 customers on January 1, 2023 to promptly return to
the interconnection customer any funds collected via a
deposit or otherwise for contributions in aid of
construction taxes, if:
(A) the income tax gross-up amounts paid by the
interconnection customer to the electric utility are
not remitted, paid, or otherwise transferred to a
relevant taxing authority or authorities by the
electric utility within 7 years of the date of
collection of such funds by the electric utility from
the interconnection customer; or
(B) to the extent such funds are paid by the
utility to the taxing authority, if such funds are
refunded to the electric utility by the relevant
taxing authority or authorities.
An electric utility serving more than 100,000
customers on January 1, 2023 shall not collect from an
interconnection customer funds meant to address
contributions in aid of construction until the tax
year in which the electric utility actually makes the
associated tax payment, remission, or transfer to the
relevant taxing authority.

HB3758 - 269 - LRB104 12225 JDS 22331 b
Nothing in this Section shall prevent an electric
utility assessing an interconnection customer charges
in the amount of income taxes actually remitted, paid,
or otherwise transferred by the electric utility to a
relevant taxing authority or authorities that arise
from the interconnection customer's interconnection to
the electric utility's system, if such amounts are in
fact remitted, paid, or otherwise transferred to a
relevant taxing authority or authorities.
The Commission shall initiate an emergency
rulemaking within 90 days of the effective date of
this amendatory Act to effectuate the requirements of
this paragraph (16).
(i) All electricity providers shall begin to offer net
metering no later than April 1, 2008.
(j) An electricity provider shall provide net metering to
eligible customers according to subsections (d), (d-5), and
(e). Eligible renewable electrical generating facilities for
which eligible customers registered for net metering before
January 1, 2025 shall continue to receive net metering
services according to subsections (d), (d-5), and (e) of this
Section for the lifetime of the system, regardless of whether
those retail customers change electricity providers or whether
the retail customer benefiting from the system changes. On and
after January 1, 2025, any eligible customer that applies for
net metering and previously would have qualified under

HB3758 - 270 - LRB104 12225 JDS 22331 b
subsections (d), (d-5), or (e) shall only be eligible for net
metering as described in subsection (n).
(k) Each electricity provider shall maintain records and
report annually to the Commission the total number of net
metering customers served by the provider, as well as the
type, capacity, and energy sources of the generating systems
used by the net metering customers. Nothing in this Section
shall limit the ability of an electricity provider to request
the redaction of information deemed by the Commission to be
confidential business information.
(l)(1) Notwithstanding the definition of "eligible
customer" in item (ii) of subsection (b) of this Section, each
electricity provider shall allow net metering as set forth in
this subsection (l) and for the following projects, provided
that only electric utilities serving more than 200,000
customers as of January 1, 2021 shall provide net metering for
projects that are eligible for subparagraph (C) of this
paragraph (1) and have energized after the effective date of
this amendatory Act of the 102nd General Assembly:
(A) properties owned or leased by multiple customers
that contribute to the operation of an eligible renewable
electrical generating facility through an ownership or
leasehold interest of at least 200 watts in such facility,
such as a community-owned wind project, a community-owned
biomass project, a community-owned solar project, or a
community methane digester processing livestock waste from

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multiple sources, provided that the facility is also
located within the utility's service territory;
(B) individual units, apartments, or properties
located in a single building that are owned or leased by
multiple customers and collectively served by a common
eligible renewable electrical generating facility, such as
an office or apartment building, a shopping center or
strip mall served by photovoltaic panels on the roof; and
(C) subscriptions to community renewable generation
projects, including community renewable generation
projects on the customer's side of the billing meter of a
host facility and partially used for the customer's own
load.
In addition, the nameplate capacity of the eligible
renewable electric generating facility that serves the demand
of the properties, units, or apartments identified in
paragraphs (1) and (2) of this subsection (l) shall not exceed
5,000 kilowatts in nameplate capacity in total. Any eligible
renewable electrical generating facility or community
renewable generation project that is powered by photovoltaic
electric energy and installed after the effective date of this
amendatory Act of the 99th General Assembly must be installed
by a qualified person in compliance with the requirements of
Section 16-128A of the Public Utilities Act and any rules or
regulations adopted thereunder.
(2) Notwithstanding anything to the contrary, an

HB3758 - 272 - LRB104 12225 JDS 22331 b
electricity provider shall provide credits for the electricity
produced by the projects described in paragraph (1) of this
subsection (l). The electricity provider shall provide credits
that include at least energy supply, capacity, transmission,
and, if applicable, the purchased energy adjustment on the
subscriber's monthly bill equal to the subscriber's share of
the production of electricity from the project, as determined
by paragraph (3) of this subsection (l). For customers with
transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall prepare a
reasonable approximation of the kilowatt-hour equivalent value
and provide that value as a monetary credit. The electricity
provider shall submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on payment
plans or participating in budget billing programs shall have
credits applied on a monthly basis.
(3) Notwithstanding anything to the contrary and
regardless of whether a subscriber to an eligible community
renewable generation project receives power and energy service
from the electric utility or an alternative retail electric
supplier, for projects eligible under paragraph (C) of
subparagraph (1) of this subsection (l), electric utilities
serving more than 200,000 customers as of January 1, 2021
shall provide the monetary credits to a subscriber's
subsequent bill for the electricity produced by community

HB3758 - 273 - LRB104 12225 JDS 22331 b
renewable generation projects. The electric utility shall
provide monetary credits to a subscriber's subsequent bill at
the utility's total price to compare equal to the subscriber's
share of the production of electricity from the project, as
determined by paragraph (5) of this subsection (l). For the
purposes of this subsection, "total price to compare" means
the rate or rates published by the Illinois Commerce
Commission for energy supply for eligible customers receiving
supply service from the electric utility, and shall include
energy, capacity, transmission, and the purchased energy
adjustment. Notwithstanding anything to the contrary,
customers on payment plans or participating in budget billing
programs shall have credits applied on a monthly basis. Any
applicable credit or reduction in load obligation from the
production of the community renewable generating projects
receiving a credit under this subsection shall be credited to
the electric utility to offset the cost of providing the
credit. To the extent that the credit or load obligation
reduction does not completely offset the cost of providing the
credit to subscribers of community renewable generation
projects as described in this subsection, the electric utility
may recover the remaining costs through its Multi-Year Rate
Plan. All electric utilities serving 200,000 or fewer
customers as of January 1, 2021 shall only provide the
monetary credits to a subscriber's subsequent bill for the
electricity produced by community renewable generation

HB3758 - 274 - LRB104 12225 JDS 22331 b
projects if the subscriber receives power and energy service
from the electric utility. Alternative retail electric
suppliers providing power and energy service to a subscriber
located within the service territory of an electric utility
not subject to Sections 16-108.18 and 16-118 shall provide the
monetary credits to the subscriber's subsequent bill for the
electricity produced by community renewable generation
projects.
(4) If requested by the owner or operator of a community
renewable generating project, an electric utility serving more
than 200,000 customers as of January 1, 2021 shall enter into a
net crediting agreement with the owner or operator to include
a subscriber's subscription fee on the subscriber's monthly
electric bill and provide the subscriber with a net credit
equivalent to the total bill credit value for that generation
period minus the subscription fee, provided the subscription
fee is structured as a fixed percentage of bill credit value.
The net crediting agreement shall set forth payment terms from
the electric utility to the owner or operator of the community
renewable generating project, and the electric utility may
charge a net crediting fee to the owner or operator of a
community renewable generating project that may not exceed 1%
2% of the subscription fee bill credit value. Notwithstanding
anything to the contrary, an electric utility serving 200,000
customers or fewer as of January 1, 2021 shall not be obligated
to enter into a net crediting agreement with the owner or

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operator of a community renewable generating project. For the
purposes of this paragraph (4), "net crediting" means a
program offered by an electric utility under which the
electric utility, upon authorization by or on behalf of a
subscriber, remits the cash value of the subscription fee to
the owner or operator of the community renewable generation
facility, without regard to whether or not the subscriber has
paid the subscriber's monthly electric bill, and places the
cash value of the remaining bill credit on the subscriber's
bill. The utility shall use the same net crediting format for
subscribers on payment plans or participating in budget
billing programs.
(5) For the purposes of facilitating net metering, the
owner or operator of the eligible renewable electrical
generating facility or community renewable generation project
shall be responsible for determining the amount of the credit
that each customer or subscriber participating in a project
under this subsection (l) is to receive in the following
manner:
(A) The owner or operator shall, on a monthly basis,
provide to the electric utility the kilowatthours of
generation attributable to each of the utility's retail
customers and subscribers participating in projects under
this subsection (l) in accordance with the customer's or
subscriber's share of the eligible renewable electric
generating facility's or community renewable generation

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project's output of power and energy for such month. The
owner or operator shall electronically transmit such
calculations and associated documentation to the electric
utility, in a format or method set forth in the applicable
tariff, on a monthly basis so that the electric utility
can reflect the monetary credits on customers' and
subscribers' electric utility bills. The electric utility
shall be permitted to revise its tariffs to implement the
provisions of this amendatory Act of the 102nd General
Assembly. The owner or operator shall separately provide
the electric utility with the documentation detailing the
calculations supporting the credit in the manner set forth
in the applicable tariff.
(B) For those participating customers and subscribers
who receive their energy supply from an alternative retail
electric supplier, the electric utility shall remit to the
applicable alternative retail electric supplier the
information provided under subparagraph (A) of this
paragraph (3) for such customers and subscribers in a
manner set forth in such alternative retail electric
supplier's net metering program, or as otherwise agreed
between the utility and the alternative retail electric
supplier. The alternative retail electric supplier shall
then submit to the utility the amount of the charges for
power and energy to be applied to such customers and
subscribers, including the amount of the credit associated

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with net metering.
(C) A participating customer or subscriber may provide
authorization as required by applicable law that directs
the electric utility to submit information to the owner or
operator of the eligible renewable electrical generating
facility or community renewable generation project to
which the customer or subscriber has an ownership or
leasehold interest or a subscription. Such information
shall be limited to the components of the net metering
credit calculated under this subsection (l), including the
bill credit rate, total kilowatthours, and total monetary
credit value applied to the customer's or subscriber's
bill for the monthly billing period.
(l-5) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility subject to this Section shall file a tariff or tariffs
to implement the provisions of subsection (l) of this Section,
which shall, consistent with the provisions of subsection (l),
describe the terms and conditions under which owners or
operators of qualifying properties, units, or apartments may
participate in net metering. The Commission shall approve, or
approve with modification, the tariff within 120 days after
the effective date of this amendatory Act of the 102nd General
Assembly.
(m) Nothing in this Section shall affect the right of an
electricity provider to continue to provide, or the right of a

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retail customer to continue to receive service pursuant to a
contract for electric service between the electricity provider
and the retail customer in accordance with the prices, terms,
and conditions provided for in that contract. Either the
electricity provider or the customer may require compliance
with the prices, terms, and conditions of the contract.
(n) On and after January 1, 2025, the net metering
services described in subsections (d), (d-5), and (e) of this
Section shall no longer be offered, except as to those
eligible renewable electrical generating facilities for which
retail customers are receiving net metering service under
these subsections at the time the net metering services under
those subsections are no longer offered; those systems shall
continue to receive net metering services described in
subsections (d), (d-5), and (e) of this Section for the
lifetime of the system, regardless of if those retail
customers change electricity providers, or whether the retail
customer benefiting from the system changes or whether the
retail customer adds storage behind the same meter even if a
new interconnection agreement is required. The electric
utility serving more than 200,000 customers as of January 1,
2021 is responsible for ensuring the billing credits continue
without lapse for the lifetime of systems, as required in
subsection (o). Those retail customers that begin taking net
metering service after the date that net metering services are
no longer offered under such subsections shall be subject to

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the provisions set forth in the following paragraphs (1)
through (3) of this subsection (n):
(1) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is not provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during the monthly billing period exceeds the
amount of electricity produced by the customer, then
the electricity provider shall charge the customer for
the net kilowatt-hour based electricity charges
reflected in the customer's electric service rate
supplied to and used by the customer as provided in
paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during the monthly billing period exceeds the
amount of electricity used by the customer during that
billing period, then the electricity provider
supplying that customer shall apply a 1:1
kilowatt-hour energy or monetary credit kilowatt-hour
supply charges to the customer's subsequent bill. The
customer shall choose between 1:1 kilowatt-hour or
monetary credit at the time of application. For the
purposes of this subsection, "kilowatt-hour supply
charges" means the kilowatt-hour equivalent values for

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energy, capacity, transmission, and the purchased
energy adjustment, if applicable. Notwithstanding
anything to the contrary, customers on payment plans
or participating in budget billing programs shall have
credits applied on a monthly basis. The electricity
provider shall continue to carry over any excess
kilowatt-hour or monetary energy credits earned and
apply those credits to subsequent billing periods. For
customers with transmission or capacity charges not
charged on a kilowatt-hour basis, the electricity
provider shall prepare a reasonable approximation of
the kilowatt-hour equivalent value and provide that
value as a monetary credit. The electricity provider
shall submit these approximation methodologies to the
Commission for review, modification, and approval.
(C) (Blank).
(2) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during any hourly period exceeds the amount
of electricity produced by the customer, then the
electricity provider shall charge the customer for the
net electricity supplied to and used by the customer

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as provided in paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during any hourly period exceeds the amount
of electricity used by the customer during that hourly
period, the energy provider shall calculate an energy
credit for the net kilowatt-hours produced in such
period, and shall apply that credit as a monetary
credit to the customer's subsequent bill. The value of
the energy credit shall be calculated using the same
price per kilowatt-hour as the electric service
provider would charge for kilowatt-hour energy sales
during that same hourly period and shall also include
values for capacity and transmission. For customers
with transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall
prepare a reasonable approximation of the
kilowatt-hour equivalent value and provide that value
as a monetary credit. The electricity provider shall
submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on
payment plans or participating in budget billing
programs shall have credits applied on a monthly
basis.
(3) An electricity provider shall provide electric
service to eligible customers who utilize net metering at

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non-discriminatory rates that are identical, with respect
to rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged
if not a net metering customer. An electricity provider
shall charge the customer for the net electricity supplied
to and used by the customer according to the terms of the
contract or tariff to which the same customer would be
assigned or be eligible for if the customer was not a net
metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements
not specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or
other requirement would apply to other similarly situated
customers who are not net metering customers. The customer
remains responsible for the gross amount of delivery
services charges, supply-related charges that are kilowatt
based, and all taxes and fees related to such charges. The
customer also remains responsible for all taxes and fees
that would otherwise be applicable to the net amount of
electricity used by the customer. Paragraphs (1) and (2)
of this subsection (n) shall not be construed to prevent
an arms-length agreement between an electricity provider
and an eligible customer that sets forth different prices,
terms, and conditions for the provision of net metering
service, including, but not limited to, the provision of

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the appropriate metering equipment for non-residential
customers. Nothing in this paragraph (3) shall be
interpreted to mandate that a utility that is only
required to provide delivery services to a given customer
must also sell electricity to such customer.
(o) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility subject to this Section shall file a tariff, which
shall, consistent with the provisions of this Section, propose
the terms and conditions under which a customer may
participate in net metering. The tariff for electric utilities
serving more than 200,000 customers as of January 1, 2021
shall also provide a streamlined and transparent bill
crediting system for net metering to be managed by the
electric utilities. The terms and conditions shall include,
but are not limited to, that an electric utility shall manage
and maintain billing of net metering credits and charges
regardless of if the eligible customer takes net metering
under an electric utility or alternative retail electric
supplier. The electric utility serving more than 200,000
customers as of January 1, 2021 shall process and approve all
net metering applications, even if an eligible customer is
served by an alternative retail electric supplier; and the
utility shall forward application approval to the appropriate
alternative retail electric supplier. Eligibility for net
metering shall remain with the owner of the utility billing

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address such that, if an eligible renewable electrical
generating facility changes ownership, the net metering
eligibility transfers to the new owner. The electric utility
serving more than 200,000 customers as of January 1, 2021
shall manage net metering billing for eligible customers to
ensure full crediting occurs on electricity bills, including,
but not limited to, ensuring net metering crediting begins
upon commercial operation date, net metering billing transfers
immediately if an eligible customer switches from an electric
utility to alternative retail electric supplier or vice versa,
and net metering billing transfers between ownership of a
valid billing address. All transfers referenced in the
preceding sentence shall include transfer of all banked
credits. All electric utilities serving 200,000 or fewer
customers as of January 1, 2021 shall manage net metering
billing for eligible customers receiving power and energy
service from the electric utility to ensure full crediting
occurs on electricity bills, ensuring net metering crediting
begins upon commercial operation date, net metering billing
transfers immediately if an eligible customer switches from an
electric utility to alternative retail electric supplier or
vice versa, and net metering billing transfers between
ownership of a valid billing address. Alternative retail
electric suppliers providing power and energy service to
eligible customers located within the service territory of an
electric utility serving 200,000 or fewer customers as of

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January 1, 2021 shall manage net metering billing for eligible
customers to ensure full crediting occurs on electricity
bills, including, but not limited to, ensuring net metering
crediting begins upon commercial operation date, net metering
billing transfers immediately if an eligible customer switches
from an electric utility to alternative retail electric
supplier or vice versa, and net metering billing transfers
between ownership of a valid billing address.
(Source: P.A. 102-662, eff. 9-15-21.)
(220 ILCS 5/16-107.6)
Sec. 16-107.6. Distributed generation rebate.
(a) In this Section:
"Additive services" means the services that distributed
energy resources provide to the energy system and society that
are not (1) already included in the base rebates for
system-wide grid services; or (2) otherwise already
compensated. Additive services may reflect, but shall not be
limited to, any geographic, time-based, performance-based, and
other benefits of distributed energy resources, as well as the
present and future technological capabilities of distributed
energy resources and present and future grid needs.
"Distributed energy resource" means a wide range of
technologies that are located on the customer side of the
customer's electric meter, including, but not limited to,
distributed generation, energy storage, electric vehicles, and

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demand response technologies.
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter.
"Smart inverter" means a device that converts direct
current into alternating current and meets the IEEE 1547-2018
equipment standards. Until devices that meet the IEEE
1547-2018 standard are available, devices that meet the UL
1741 SA standard are acceptable.
"Subscriber" has the meaning set forth in Section 1-10 of
the Illinois Power Agency Act.
"Subscription" has the meaning set forth in Section 1-10
of the Illinois Power Agency Act.
"System-wide grid services" means the benefits that a
distributed energy resource provides to the distribution grid
for a period of no less than 25 years. System-wide grid
services do not vary by location, time, or the performance
characteristics of the distributed energy resource.
System-wide grid services include, but are not limited to,
avoided or deferred distribution capacity costs, resilience
and reliability benefits, avoided or deferred distribution
operation and maintenance costs, distribution voltage and

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power quality benefits, and line loss reductions.
"Threshold date" means December 31, 2024 or the date on
which the utility's tariff or tariffs setting the new
compensation values established under subsection (e) take
effect, whichever is later.
(b) An electric utility that serves more than 200,000
customers in the State shall file a petition with the
Commission requesting approval of the utility's tariff to
provide a rebate to the owner or operator of distributed
generation, including third-party owned systems, that meets
the following criteria:
(1) has a nameplate generating capacity no greater
than 5,000 kilowatts and is primarily used to offset a
customer's electricity load;
(2) is located on the customer's side of the billing
meter and for the customer's own use;
(3) is interconnected to electric distribution
facilities owned by the electric utility under rules
adopted by the Commission by means of the inverter or
smart inverter required by this Section, as applicable.
For purposes of this Section, "distributed generation"
shall satisfy the definition of distributed renewable energy
generation device set forth in Section 1-10 of the Illinois
Power Agency Act to the extent such definition is consistent
with the requirements of this Section.
In addition, any new photovoltaic distributed generation

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that is installed after June 1, 2017 (the effective date of
Public Act 99-906) must be installed by a qualified person, as
defined by subsection (i) of Section 1-56 of the Illinois
Power Agency Act.
The tariff shall include a base rebate that compensates
distributed generation for the system-wide grid services
associated with distributed generation and, after the
proceeding described in subsection (e) of this Section, an
additional payment or payments for the additive services. The
tariff shall provide that the smart inverter associated with
the distributed generation shall provide autonomous response
to grid conditions through its default settings as approved by
the Commission. Default settings may not be changed after the
execution of the interconnection agreement except by mutual
agreement between the utility and the owner or operator of the
distributed generation. Nothing in this Section shall negate
or supersede Institute of Electrical and Electronics Engineers
equipment standards or other similar standards or
requirements. The tariff shall not limit the ability of the
smart inverter or other distributed energy resource to provide
wholesale market products such as regulation, demand response,
or other services, or limit the ability of the owner of the
smart inverter or the other distributed energy resource to
receive compensation for providing those wholesale market
products or services.
(b-5) Within 30 days after the effective date of this

HB3758 - 289 - LRB104 12225 JDS 22331 b
amendatory Act of the 102nd General Assembly, each electric
public utility with 3,000,000 or more retail customers shall
file a tariff with the Commission that further compensates any
retail customer that installs or has installed photovoltaic
facilities paired with energy storage facilities on or
adjacent to its premises for the benefits the facilities
provide to the distribution grid. The tariff shall provide
that, in addition to the other rebates identified in this
Section, the electric utility shall rebate to such retail
customer (i) the previously incurred and future costs of
installing interconnection facilities and related
infrastructure to enable full participation in the PJM
Interconnection, LLC or its successor organization frequency
regulation market; and (ii) all wholesale demand charges
incurred after the effective date of this amendatory Act of
the 102nd General Assembly. The Commission shall approve, or
approve with modification, the tariff within 120 days after
the utility's filing.
(c) The proposed tariff authorized by subsection (b) of
this Section shall include the following participation terms
for rebates to be applied under this Section for distributed
generation that satisfies the criteria set forth in subsection
(b) of this Section:
(1) The owner or operator of distributed generation
that services customers not eligible for net metering
under subsection (d), (d-5), or (e) of Section 16-107.5 of

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this Act may apply for a rebate as provided for in this
Section. Until the threshold date, the value of the rebate
shall be $250 per kilowatt of nameplate generating
capacity, measured as nominal DC power output, of that
customer's distributed generation. To the extent the
distributed generation also has an associated energy
storage, then the energy storage system shall be
separately compensated with a base rebate of $250 per
kilowatt-hour of nameplate capacity. Any distributed
generation device that is compensated for storage in this
subsection (1) before the threshold date shall participate
in one or more programs determined through the Multi-Year
Integrated Grid Planning process that are designed to meet
peak reduction and flexibility, the virtual power plant
program described in Section 16-107.9, or the peak
remediation program described in Section 16-107.10. After
the threshold date, the value of the base rebate and
additional compensation for any additive services shall be
as determined by the Commission in the proceeding
described in subsection (e) of this Section, provided that
the value of the base rebate for system-wide grid services
shall not be lower than $250 per kilowatt of nameplate
generating capacity of distributed generation or community
renewable generation project and shall not be lower than
$150 per kilowatt-hour of nameplate generating capacity of
associated energy storage.

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(2) The owner or operator of distributed generation
that, before the threshold date, would have been eligible
for net metering under subsection (d), (d-5), or (e) of
Section 16-107.5 of this Act and that has not previously
received a distributed generation rebate, may apply for a
rebate as provided for in this Section. Until the
threshold date, the value of the base rebate shall be $300
per kilowatt of nameplate generating capacity, measured as
nominal DC power output, of the distributed generation.
The owner or operator of distributed generation that,
before the threshold date, is eligible for net metering
under subsection (d), (d-5), or (e) of Section 16-107.5 of
this Act may apply for a base rebate for an energy storage
device that uses the same smart inverter as the
distributed generation, regardless of whether the
distributed generation applies for a rebate for the
distributed generation device. The energy storage system
shall be separately compensated at a base payment of $300
per kilowatt-hour of nameplate capacity. Any distributed
generation device that is compensated for storage in this
subsection (2) before the threshold date shall participate
in the virtual power plant program described in Section
16-107.9, or at least one demand response a peak time
rebate program, hourly pricing program, or time-of-use
rate program that is offered by the applicable electric
utility, an alternative retail electric supplier, or an

HB3758 - 292 - LRB104 12225 JDS 22331 b
entity qualified to offer demand response that is not an
alternative retail electric supplier. After the threshold
date, the value of the base rebate and additional
compensation for any additive services shall be as
determined by the Commission in the proceeding described
in subsection (e) of this Section, provided that, prior to
December 31, 2029, the value of the base rebate for
system-wide services shall not be lower than $300 per
kilowatt of nameplate generating capacity of distributed
generation, after which it shall not be lower than $250
per kilowatt of nameplate capacity and shall not be lower
than $150 per kilowatt-hour of nameplate generating
capacity of associated energy storage.
(3) Upon approval of a rebate application submitted
under this subsection (c), the retail customer shall no
longer be entitled to receive any delivery service credits
for the excess electricity generated by its facility and
shall be subject to the provisions of subsection (n) of
Section 16-107.5 of this Act unless the owner or operator
receives a rebate only for an energy storage device and
not for the distributed generation device.
(4) To be eligible for a rebate described in this
subsection (c), the owner or operator of the distributed
generation must have a smart inverter installed and in
operation on the distributed generation.
(5) Any distributed generation or energy storage

HB3758 - 293 - LRB104 12225 JDS 22331 b
device applying for a rebate under paragraphs (1) or (2)
of this subsection (c) after the effective date of this
Amendatory Act of the 104th General Assembly shall be
eligible for the following additional payment or payments
in addition to the applicable rebate under paragraphs (1)
or (2) of this subsection (c):
(A) An amount set by the tariff approved pursuant
to subsection (e) of this Section but not less than
$25/kWdc for distributed generation or $25/kWh of
nameplate capacity for energy storage devices (whether
or not paired with distributed generation) located in
an equity investment eligible community, as defined in
Section 1-10 of the Illinois Power Agency Act, at the
time the interconnection agreement is signed.
Notwithstanding anything to the contrary, a community
renewable generation project and energy storage
devices coupled with a community renewable generation
project shall be eligible for the rebates described in
this subparagraph;
(B) An amount set by the tariff approved pursuant
to subsection (e) of this Section but not less than
$100/kWh of nameplate capacity for energy storage
devices that neither share an inverter with
distributed generation nor are interconnected behind
the same retail customer meter as distributed
generation.

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(d) The Commission shall review the proposed tariff
authorized by subsection (b) of this Section and may make
changes to the tariff that are consistent with this Section
and with the Commission's authority under Article IX of this
Act, subject to notice and hearing. Following notice and
hearing, the Commission shall issue an order approving, or
approving with modification, such tariff no later than 240
days after the utility files its tariff. Upon the effective
date of this amendatory Act of the 102nd General Assembly, an
electric utility shall file a petition with the Commission to
amend and update any existing tariffs to comply with
subsections (b) and (c).
(e) By no later than June 30, 2023, the Commission shall
open an independent, statewide investigation into the value
of, and compensation for, distributed energy resources. The
Commission shall conduct the investigation, but may arrange
for experts or consultants independent of the utilities and
selected by the Commission to assist with the investigation.
The cost of the investigation shall be shared by the utilities
filing tariffs under subsection (b) of this Section but may be
recovered as an expense through normal ratemaking procedures.
(1) The Commission shall ensure that the investigation
includes, at minimum, diverse sets of stakeholders; a
review of best practices in calculating the value of
distributed energy resource benefits; a review of the full
value of the distributed energy resources and the manner

HB3758 - 295 - LRB104 12225 JDS 22331 b
in which each component of that value is or is not
otherwise compensated; and assessments of how the value of
distributed energy resources may evolve based on the
present and future technological capabilities of
distributed energy resources and based on present and
future grid needs.
(2) The Commission's final order concluding this
investigation shall establish an annual process and
formula for the compensation of distributed generation and
energy storage systems, and an initial set of inputs for
that formula. The Commission's final order concluding this
investigation shall establish base rebates that compensate
distributed generation, community renewable generation
projects and energy storage systems for the system-wide
grid services that they provide. Those base rebate values
shall be consistent across the state, and shall not vary
by customer, customer class, customer location, or any
other variable. With respect to rebates for distributed
generation or community renewable generation projects,
that rebate shall not be lower than $250 per kilowatt of
nameplate generating capacity of the distributed
generation or community renewable generation project. The
Commission's final order concluding this proceeding shall
also direct the utilities to update the formula, on an
annual basis, with inputs derived from their integrated
grid plans developed pursuant to Section 16-105.17. The

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base rebate shall be updated annually based on the annual
updates to the formula inputs, but, with respect to
rebates for distributed generation or community renewable
generation projects, shall be no lower than $250 per
kilowatt of nameplate generating capacity of the
distributed generation or community renewable generation
project.
(3) The Commission shall also determine, as a part of
its investigation under this subsection, whether
distributed energy resources can provide any additive
services. Those additive services may include services
that are provided through utility-controlled responses to
grid conditions. If the Commission determines that
distributed energy resources can provide additive grid
services, the Commission shall determine the terms and
conditions for the operation and compensation of those
services. That compensation shall be above and beyond the
base rebate that the distributed energy generation,
community renewable generation project and energy storage
system receives. Compensation for additive services may
vary by location, time, performance characteristics,
technology types, or other variables.
(4) The Commission shall ensure that compensation for
distributed energy resources, including base rebates and
any payments for additive services, shall reflect all
reasonably known and measurable values of the distributed

HB3758 - 297 - LRB104 12225 JDS 22331 b
generation over its full expected useful life.
Compensation for additive services shall reflect, but
shall not be limited to, any geographic, time-based,
performance-based, and other benefits of distributed
generation, as well as the present and future
technological capabilities of distributed energy resources
and present and future grid needs.
(5) The Commission shall consider the electric
utility's integrated grid plan developed pursuant to
Section 16-105.17 of this Act to help identify the value
of distributed energy resources for the purpose of
calculating the compensation described in this subsection.
(6) The Commission shall determine additional
compensation for distributed energy resources that creates
savings and value on the distribution system by being
co-located or in close proximity to electric vehicle
charging infrastructure in use by medium-duty and
heavy-duty vehicles, primarily serving environmental
justice communities, as outlined in the utility integrated
grid planning process under Section 16-105.17 of this Act.
No later than 60 days after the Commission enters its
final order under this subsection (e), each utility shall file
its updated tariff or tariffs in compliance with the order,
including new tariffs for the recovery of costs incurred under
this subsection (e) that shall provide for volumetric-based
cost recovery, and the Commission shall approve, or approve

HB3758 - 298 - LRB104 12225 JDS 22331 b
with modification, the tariff or tariffs within 240 days after
the utility's filing.
(f) Notwithstanding any provision of this Act to the
contrary, the owner or operator of a community renewable
generation project as defined in Section 1-10 of the Illinois
Power Agency Act shall also be eligible to apply for the rebate
described in this Section. The owner or operator of the
community renewable generation project may apply for a rebate
only if the owner or operator, or previous owner or operator,
of the community renewable generation project has not already
submitted an application, and, regardless of whether the
subscriber is a residential or non-residential customer, may
be allowed the amount identified in paragraph (1) of
subsection (c) applicable on the date that the application is
submitted.
(g) The owner of the distributed generation or community
renewable generation project may apply for the rebate or
rebates approved under this Section at the time of execution
of an interconnection agreement with the distribution utility
and shall receive the value available at that time of
execution of the interconnection agreement, provided the
project reaches mechanical completion within 24 months after
execution of the interconnection agreement. If the project has
not reached mechanical completion within 24 months after
execution, the owner may reapply for the rebate or rebates
approved under this Section available at the time of

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

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

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To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, the
utility's actual year-end capital structure that includes
a common equity ratio, excluding goodwill, of up to and
including 50% of the total capital structure shall be
deemed reasonable and used to set rates.
(2) The utility, at its election, may recover all of
the costs as part of a filing for a general increase in
rates under Article IX of this Act, as part of an annual
filing to update a performance-based formula rate under
subsection (d) of Section 16-108.5 of this Act, or through
an automatic adjustment clause tariff, provided that
nothing in this paragraph (2) permits the double recovery
of such costs from customers. If the utility elects to
recover the costs it incurs under subsections (b) and (c)
through an automatic adjustment clause tariff, the utility
may file its proposed tariff together with the tariff it
files under subsection (b) of this Section or at a later
time. The proposed tariff shall provide for an annual
reconciliation, less any deferred taxes related to the
reconciliation, with interest at an annual rate of return
equal to the utility's weighted average cost of capital as
calculated under paragraph (1) of this subsection (h),
including a revenue conversion factor calculated to

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recover or refund all additional income taxes that may be
payable or receivable as a result of that return, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the
utility files its automatic adjustment clause tariff under
this subsection (h), with what the revenue requirement
would have been had the actual cost information for the
applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(i) An electric utility shall recover from its retail
customers, on a volumetric basis, all of the costs of the
rebates made under a tariff or tariffs placed into effect
under subsection (e) of this Section, including, but not
limited to, the value of the rebates and all costs incurred by
the utility to comply with and implement subsection (e) of
this Section, consistent with the following provisions:
(1) The utility may defer a portion of its costs as a
regulatory asset. The Commission shall determine the
portion that may be appropriately deferred as a regulatory

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asset. Factors that the Commission shall consider in
determining the portion of costs that shall be deferred as
a regulatory asset include, but are not limited to: (i)
whether and the extent to which a cost effectively
deferred or avoided other distribution system operating
costs or capital expenditures; (ii) the extent to which a
cost provides environmental benefits; (iii) the extent to
which a cost improves system reliability or resilience;
(iv) the electric utility's distribution system plan
developed pursuant to Section 16-105.17 of this Act; (v)
the extent to which a cost advances equity principles; and
(vi) such other factors as the Commission deems
appropriate. The remainder of costs shall be deemed an
operating expense and shall be recoverable if found
prudent and reasonable by the Commission.
The total costs deferred as a regulatory asset shall
be amortized over a 15-year period. The unamortized
balance shall be recognized as of December 31 for a given
year. The utility shall also earn a return on the total of
the unamortized balance of the regulatory assets, less any
deferred taxes related to the unamortized balance, at an
annual rate equal to the utility's weighted average cost
of capital that includes, based on a year-end capital
structure, the utility's actual cost of debt for the
applicable calendar year and a cost of equity, which shall
be calculated as the sum of: (I) the average for the

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

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applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(j) No later than 90 days after the Commission enters an
order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under this Section, the
electric utility shall provide notice of the availability of
rebates under this Section.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
(220 ILCS 5/16-107.8 new)
Sec. 16-107.8. Demand response virtual power plant
program.
(a) In this Section:
"Aggregator" means a party, other than the electric
utility or its affiliate, that (i) represents and aggregates
the load of participating customers who collectively have the
ability to curtail 100 kilowatts or more through demand
response technologies and (ii) is responsible for performance
of the aggregation in the program.

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"Demand response technologies" means applications or
solutions, not including electricity generators, that can be
controlled to respond to pricing, or provide services,
including decrease peak electricity demand or shift demand
from peak to off-peak periods. Demand response technologies
may include, but are not limited to, connected devices such as
behind-the-meter energy storage systems, smart thermostats,
air conditioning units, electric vehicle batteries, and
electric vehicle supply equipment.
"Distributed energy resources management system" or
"DERMS" means a platform that may be used by distribution
system operators or utilities to integrate grid resources,
such as distributed energy resources, into system operations.
"Energy storage system" has the meaning set forth in
subsection (a) of Section 16-107.6.
"Event" means a time period defined consistent with the
requirements of this Section by the applicable electric
utility where deployment of demand response technologies is
measured and compensated under this Section.
"Export" means the discharge of energy from an energy
storage system to the distribution grid in response to
pricing, or to provide services, including decreasing peak
electricity demand or shifting demand from peak to off-peak
periods.
"Participating customer" means a retail customer as
defined in Section 16-102 with one or more demand response

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technologies.
(b) The General Assembly finds that when demand response
technologies commit to deployment at times of stress on the
grid and in wholesale energy markets, the actual deployment
benefits all customers of the utility with enhanced grid
reliability and protection from retail and wholesale price
increases and that those socialized goods should be encouraged
and compensated.
(c) Within 60 days of the effective date of this
amendatory Act of the 104th General Assembly, each electric
utility serving more than 300,000 customers as of January 1,
2023 shall propose one or more tariffs applicable to demand
response technologies. The tariffs shall be consistent with
the following:
(1) Each request by the utility for an aggregator or
participating customer to deploy demand response
technologies participating in the program as identified in
advance by the aggregator or participating customer shall
be an event. Each utility shall rely on the demand
response technologies addressed within a tariff a minimum
number of events specified in the tariff.
(2) In exchange for an aggregator, or a participating
customer not using an aggregator, facilitating curtailment
through demand response technologies, the utility shall
after demonstrated performance by the aggregator or
participating customer, compensate the aggregator or

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participating customer in a manner to be determined by the
Commission. The Commission may consider separate
compensation for response to events called on less than 24
hours notice and compensation for response to events
called on 24 hours or more notice. In determining the
value of the performance payment, the Commission shall at
minimum consider the benefits to the utility and
ratepayers of peak remediation, reduced capacity and
transmission allocations to the applicable regional
transmission organization zone, and a reasonable
estimation of the value of reduced transmission and
distribution investment and other grid services. The value
shall be set to encourage robust participation. At least
30 days prior to proposing any tariff relating to demand
response technologies, utilities shall jointly conduct at
least one meeting with interested potential aggregators
and participating customers to identify types of demand
response technologies and compensation suitable for
inclusion in the tariff.
(3) An aggregator, or participating customer applying
individually, must represent that it has identified for
participation demand response technologies with an
aggregate curtailment capacity of at least 100 kilowatts
or any amount greater than that amount. Nothing in the
tariffs shall require a particular participating customer,
whether using an aggregator or not, to deploy at any

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particular time.
(4) The utility shall not send or receive signals
directly to or from any participating customer represented
by an aggregator for an event under the demand response
virtual power plant program described in this Section.
(5) The aggregator may have capabilities to receive
dispatch signals from utilities or utility-contracted
DERMS providers through communication protocols, such as
IEEE 2030.5 or OpenADR, or through such other protocol as
the Commission may approve. To facilitate adoption and
participation, the utility must also allow and enable
participating customers to expeditiously share their
customer information with aggregators and provide dispatch
signals in the form of an email or mutually agreeable
implementation.
(6) A participating customer with multiple demand
response technologies may enroll the technologies either
directly without an aggregator or through one or more
aggregators in applicable programs under the tariffs
approved under this section, so long as no particular
technology is accounted for more than once. An aggregator,
or a participating customer not using an aggregator, may
collect and rely on data created by the demand response
technologies for the purpose of demonstrating performance
in response to an event.
(7) A participating customer may enroll in the demand

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response virtual power plant program directly if eligible
or through an aggregator for one or more years and the
electric utility shall not set a minimum or maximum length
of participation for demand response technologies. The
utility shall not limit the number of participating
customers, nor shall any customer be prohibited from
participating due to its rate class.
(8) The electric utility may include reasonable
requirements for participation consistent with this
subsection except that the utility may not require
collateral from a participating customer or an aggregator
and neither the utility nor entities with which the
utility shares a common parent may be an aggregator. The
electric utility shall not penalize a participating
customer or aggregator for a participating customer
exporting during an event and the electric utility shall
not require preapproval for customer export during an
event.
(9) The utility shall recover the costs of the demand
response virtual power plant program through delivery
rates, including delivery rates authorized by the
multi-year rate plan.
(d) The Commission shall approve or approve with
modifications the tariffs filed by each utility pursuant to
subsection (c) within 240 days of filing by the utility. At any
time, the utility may propose revisions to the tariff required

HB3758 - 311 - LRB104 12225 JDS 22331 b
under this Section and the Commission may approve such
revisions if, in addition to requirements under Article IX of
this Act, such revisions are consistent with the requirements
of this Section.
(e) Not more than 6 months after 2 full delivery years of
operation of the tariffs authorized in this Section, the
Commission shall issue a report to the General Assembly
assessing the value and efficacy of the demand response
virtual power plant program, including proposals for
expansions or modifications.
(f) Nothing in the demand response virtual power plant
program shall either prevent the participating customer from
participating, directly or through a third-party aggregator,
in any other program, including any program required or
authorized by Section 16-107.6 of this Act.
(g) The Commission may consider approving additional
compensation to aggregators to the extent that the
aggregators' participating customers or participating
customers are located in equity investment eligible
communities, as that term is defined in Section 1-10 of the
Illinois Power Agency Act.
(h) The tariffs approved by the Commission shall not
reflect any additional charges, fees, or insurance
requirements imposed on those owning or operating demand
response technologies beyond those imposed on similarly
situated customers that do not own or operate such.

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(i) If a utility issuing tariffs under this Section
conducts measurement and verification prescribed by the
Commission, notwithstanding anything to the contrary all
curtailment associated with demand response technologies
taking service under such tariffs shall be counted towards
such utility's peak load reduction performance metric
authorized by item (ii) of subparagraph (A) of paragraph (2)
of subsection (e) of Section 16-108.18 of this Act and such
utility's demand response obligations under Section 8-103B of
this Act. The Commission shall not require demand response
technologies to participate in any capacity or demand response
markets or programs as a condition of the load attributable to
participating systems to count toward the utility's peak load
reduction performance metric or demand response obligations.
(220 ILCS 5/16-107.9 new)
Sec. 16-107.9. Virtual power plant program.
(a) In this Section:
"Aggregator" means a party, other than the electric
utility or its affiliate, that (i) represents and aggregates
the load of participating customers who collectively have the
ability to deploy 100 kilowatts or more of deployment of
eligible devices and (ii) is responsible for performance of
the aggregation in the program.
"Distributed energy resources management system" or
"DERMS" means a platform that may be used by distribution

HB3758 - 313 - LRB104 12225 JDS 22331 b
system operators or utilities to integrate grid resources such
as distributed energy resources into system operations.
"Distributed renewable energy generation device" has the
meaning set forth in Section 1-10 of the Illinois Power Agency
Act.
"Eligible devices" means a distributed renewable energy
device paired with one or more energy storage systems.
"Energy storage system" has the meaning set forth in
subsection (a) of Section 16-107.6.
"Participating customer" means a retail customer as
defined in Section 16-102 with one or more eligible devices,
including a community renewable generation project.
"Smart inverter" has the meaning set forth in subsection
(a) of Section 16-107.6.
(b) The General Assembly finds that when eligible devices
commit to deployment at times of stress on the grid and in
wholesale energy markets, the actual deployment benefits all
customers of the utility with enhanced reliability and
protection from wholesale price increases and that those
socialized goods should be encouraged and compensated.
(c) Within 60 days after the effective date of this
amendatory Act of the 104th General Assembly, each electric
utility serving more than 300,000 customers as of January 1,
2023, shall propose an initial tariff. The initial tariff
shall be consistent with the following:
(1) Each request by the utility for an aggregator or

HB3758 - 314 - LRB104 12225 JDS 22331 b
participating customer to deploy eligible devices
participating in the program as identified in advance by
the aggregator or participating customer shall be an
event. The utility shall provide at least 24 hours of
notice for an event compensated under paragraph (2) of
this subsection (c), however nothing prohibits the utility
from proposing distinct compensation for responses to
events called on less than 24 hours advance notice.
(2) In exchange for an aggregator facilitating the
dispatch of eligible systems during hours identified by
the utility under this tariff or a participating customer
not using an aggregator dispatching, with each time period
being an event, not to exceed 60 hours in a calendar year
and not to exceed 2 consecutive hours, the utility shall,
at the end of each delivery year during which an
aggregator participates, compensate the aggregator in an
amount per kilowatt multiplied by the average number of
kilowatts discharged during events in a delivery year by
those eligible systems enrolled with the aggregator, with
the amount per kilowatt to be determined by the
Commission. Discharge shall be measured by the total power
and energy measured by the inverter of the eligible device
and shall not distinguish between power and energy from
the distributed renewable energy generation device or the
energy storage system. In determining the value of the
performance payment, the Commission shall, at minimum,

HB3758 - 315 - LRB104 12225 JDS 22331 b
consider the benefits to the utility and ratepayers of
peak remediation, reduced capacity and transmission
allocations to the applicable regional transmission
organization zone, and a reasonable estimation of the
value of reduced transmission investment and other grid
services not compensated by tariffs authorized under
Section 16-107.6. The value shall be set to encourage
robust participation and shall be for a term of no less
than 5 years. At no time shall the compensation per
average kilowatt of demand reduction delivered be less
than $250.
(3) An aggregator or participating customer applying
individually must represent that it has identified for
participation one or more eligible devices with an
aggregate export capacity of at least 100 kilowatts or any
greater amount. Nothing in the tariff shall require a
particular participating customer using an aggregator
deploy at any particular time.
(4) The utility shall not send or receive signals
directly to or from any participating customer represented
by an aggregator for an event under the virtual power
plant program described in this Section.
(5) The aggregator may have capabilities to receive
dispatch signals from utilities or utility-contracted
DERMS providers through communication protocols, such as
IEEE 2030.5 or OpenADR, or through other protocol as the

HB3758 - 316 - LRB104 12225 JDS 22331 b
Commission may approve. To facilitate adoption and
participation, the utility must also provide dispatch
signals in the form of an email or mutually agreeable
implementation.
(6) Notwithstanding anything to the contrary, nothing
prohibits a participating customer from simultaneously
being a participating customer and taking service under
tariffs authorized by Section 16-107.5 or 16-107.6.
(7) A participating customer may enroll in the virtual
power plant program directly if eligible or through an
aggregator for one or more years, and the electric utility
shall not set a minimum or maximum length of participation
for an eligible system represented by an aggregator. The
utility shall not limit the number of participating
customers nor shall any customer be prohibited from
participating due to its rate class.
(8) The electric utility may include reasonable
requirements for participation consistent with this
subsection except that the utility may not require
collateral from a participating customer or an aggregator
and neither the utility nor entities with which the
utility shares a common parent may be an aggregator. In no
event may the electric utility call an event with less
than 24 hours' prior notice and in no event may one or more
events on a single calendar day total more than 2 hours.
The electric utility shall not penalize a participating

HB3758 - 317 - LRB104 12225 JDS 22331 b
customer or aggregator for a participating customer
exporting during an event, and the electric utility shall
not require preapproval for customer export during an
event.
(9) The utility shall recover the costs of the virtual
power plant program through delivery rates, including
delivery rates authorized by the Multi-Year Rate Plan.
(d) The Commission shall approve or approve with
modifications the tariff filed by each utility pursuant to
subsection (c) within 240 days after its filing by the
utility. At any time, the utility may propose revisions to the
initial tariff or any revisions to those revisions, and the
Commission shall approve such revisions if, in addition to
requirements under Article IX, such revisions are consistent
with the requirements of this Section.
(e) Not more than 6 months after 2 full delivery years of
operation of the tariffs authorized in this Section, the
Commission shall issue a report to the General Assembly
assessing the value and efficacy of the virtual power plant
program, including proposals for expansions or modifications.
(f) Nothing in the virtual power plant program shall
either prevent the participating customer from participating,
directly or through a third-party aggregator, in any other
program, including any program required or authorized by
Section 16-107.5 or 16-107.6, or impair the entitlement of any
participating customer to benefits authorized to the

HB3758 - 318 - LRB104 12225 JDS 22331 b
participating customer by Section 16-107.5.
(g) The Commission may consider providing compensation to
aggregators or participating customers not using an aggregator
to the extent that the aggregators' participating customers or
participating customers not using an aggregator are located in
equity investment eligible communities, as that term is
defined in Section 1-10 of the Illinois Power Agency Act.
(h) The tariffs approved by the Commission shall not
reflect any additional charges, fees, or insurance
requirements imposed on those owning or operating distributed
renewable energy generation devices, distributed energy
resources, or energy storage systems beyond those imposed on
similarly situated customers that do not own or operate these
resources.
(i) If a utility issuing a tariff under this Section
conducts measurement and verification prescribed by the
Commission, notwithstanding anything to the contrary all
discharge from distributed renewable generation devices taking
service under the tariff shall be counted towards the
utility's peak load reduction performance metric authorized by
item (ii) of subparagraph (A) of paragraph (2) of subsection
(e) of Section 16-108.18. The Commission shall not require an
eligible system to participate in any capacity or demand
response markets or programs as a condition of the load
reduction attributable to participating systems to count
toward the utility's peak load reduction performance metric.

HB3758 - 319 - LRB104 12225 JDS 22331 b
(220 ILCS 5/16-107.10 new)
Sec. 16-107.10. Peak remediation program.
(a) In this Section:
"Community renewable generation project" has the meaning
set forth in Section 1-10 of the Illinois Power Agency Act.
"Defined discharge hours" means the defined hours in the
initial tariff or subsequent tariffs that an eligible device
is eligible to receive a peak discharge payment per
kilowatt-hour of energy discharged.
"Eligible device" means a community renewable generation
project paired with one or more energy storage systems.
"Energy storage system" has the meaning set forth in
subsection (a) of Section 16-107.6.
"Nameplate capacity" has the meaning set forth in Section
1-10 of the Illinois Power Agency Act.
"Peak discharge payment" means a price per kilowatt hour
paid for energy discharged from an eligible device during the
defined discharge hours.
"Threshold date" has the meaning set forth in subsection
(a) of Section 16-107.6.
(b) The General Assembly finds that the electric grid sees
high demand for electricity but fewer renewable resources
available to meet that high demand. The General Assembly
further finds that all ratepayers benefit from deployment of
energy storage in a way that alleviates stress on the grid and

HB3758 - 320 - LRB104 12225 JDS 22331 b
reduces the costs for ratepayers frequently allocated during
those peak hours.
(c) Within 90 days after the effective date of this
amendatory Act of the 104th General Assembly, each electric
utility serving more than 300,000 retail customers as of
January 1, 2023 shall propose an initial tariff. The initial
tariff shall be consistent with the following:
(1) The utility shall compensate eligible devices with
a nameplate capacity of at least 100 kilowatts but no more
than 5,000 kilowatts for discharging into the grid during
defined discharge hours.
(2) The defined discharge hours shall be the hours of
4 p.m. through 8 p.m. on days during the months of June,
July, August, and September.
(3) In exchange for generating and providing through
its meter to the utility's distribution system at least 50
kilowatts during defined discharge hours, the utility
shall compensate the owner or operator of the eligible
device or a third party designated by the owner or
operator of the eligible device a peak discharge payment
in an amount to be determined by the Commission in
proportion to the average discharge during the hours
according to a pre-defined per kilowatt average discharge
payment. Discharge shall be measured by the total power
and energy measured by the inverter of the eligible device
and shall not distinguish between power and energy from

HB3758 - 321 - LRB104 12225 JDS 22331 b
the distributed renewable energy generation device or the
energy storage system.
(4) In determining the value of the peak discharge
payment for each participating utility, the Commission
shall, at minimum, consider the benefits to the utility
and ratepayers of peak remediation, reduced capacity, and
transmission allocations to the applicable regional
transmission organization zone, and a reasonable
estimation of the value of reduced transmission investment
and other grid services not compensated by tariffs
authorized under Section 16-107.6. The value shall be set
to encourage robust participation and shall be for a term
of no less than 15 years. The utility shall not limit the
number or capacity of participating devices.
(5) The electric utility may include reasonable
requirements for participation consistent with this
subsection except that the utility may not require
collateral from the owner or operator of a participating
eligible device.
(6) Nothing in the tariff or this Section shall
separately or independently authorize the utility to
control deployment of the storage device.
(7) The utility shall recover the costs incurred under
the tariff through delivery rates, including delivery
rates authorized by the Multi-Year Rate Plan.
(d) The Commission shall approve or approve with

HB3758 - 322 - LRB104 12225 JDS 22331 b
modifications the initial tariff filed by each utility
pursuant to subsection (c) within 240 days after filing by the
utility. At any time, the utility may propose revisions to the
initial tariff or any revisions to those revisions, and the
Commission shall approve such revisions if, in addition to
requirements under Article IX, such revisions are consistent
with the requirements of this Section.
(e) After the threshold date, the utility shall file an
annual petition to update the initial tariff for eligible
systems that begin to take service under the tariff during the
annual period. The utility shall be allowed to update the peak
discharge payment and defined discharge hours, which shall not
begin earlier than 4 p.m., but must otherwise meet all the
requirements under subsection (c). The Commission shall
approve the petition to update the initial tariff within 90
days after the petition is filed.
(f) Nothing in this Section, including any rule,
regulation, or tariff authorized by this Section, shall
prevent the eligible device or any component of the eligible
device from participating in any program required or
authorized by Section 16-107.6, nor shall it impair the
entitlement of any participating customer to benefits
authorized by Section 16-107.5.
(g) The tariffs approved by the Commission shall not
reflect any additional charges, fees, or insurance
requirements imposed on those owning or operating distributed

HB3758 - 323 - LRB104 12225 JDS 22331 b
renewable energy generation device, distributed energy
resources, or energy storage system beyond those imposed on
similarly situated customers that do not own or operate these
resources.
(h) If a utility issuing a tariff under this Section
conducts measurement and verification prescribed by the
Commission, notwithstanding anything to the contrary, all
discharge from community renewable generation projects taking
service under the tariff shall be counted toward the utility's
peak load reduction performance metric authorized by item (ii)
of subparagraph (A) of paragraph (2) of subsection (e) of
Section 16-108.18. The Commission shall not require an
eligible system to participate in any capacity or demand
response markets or programs as a condition of the load
reduction attributable to participating systems to count
toward the utility's peak load reduction performance metric.
(220 ILCS 5/16-107.11 new)
Sec. 16-107.11. Stand-alone energy storage distribution
deployment program.
(a) In this Section:
"Calendar quarter" means each of the following four
periods: (1) the months of January, February, and March; (2)
the months of April, May, and June; (3) the months of July,
August, and September; and (4) the months of October,
November, and December.

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"Capacity amount" means the participating capacity of the
stand-alone energy storage system, as measured pursuant to the
terms of this Section, multiplied by (i) the applicable
capacity price (in $/kW-day) set by the regional transmission
organization, and (ii) the number of days during the
applicable billing cycle.
"Day" means the 24-hour period commencing immediately
following midnight central prevailing time and ending on the
following midnight central prevailing time.
"Eligible device" means a stand-alone energy storage
system.
"Export" means electric power and energy sent from the
stand-alone energy storage system, through the interconnecting
utility's meter, and to the interconnecting utility's
distribution system.
"Import" means electric power and energy taken from the
interconnecting utility's distribution system, through the
interconnecting utility's meter, and to the stand-alone energy
storage system, primarily for the purpose of charging the
stand-alone energy storage device.
"Meter" means the meter owned and operated by the
interconnecting utility (or third party as allowed by the
interconnecting utility's tariffs) measuring the power and
energy imported to and exported from the stand-alone energy
storage system.
"Nameplate capacity" means the aggregate inverter capacity

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of a stand-alone energy storage system, measured in kilowatts
alternating current.
"Participating capacity" means the capacity of a
stand-alone energy storage system, measured in kilowatts
alternating current, that the system owner or operator
designates to participate in the stand alone energy storage
program. The participating capacity may be any value less than
or equal to the "nameplate capacity" of the stand-alone energy
storage system under the terms of this section. "Responding
event" means a scheduled event during which the stand-alone
energy storage system exports kilowatt-hours equal to at least
90% of the product of (1) the length of the scheduled event in
hours (expressed as a decimal to at least two places);
multiplied by (2) the participating capacity. Notwithstanding
the preceding, every kilowatt-hour generated during an
unscheduled event during the same day shall count toward
kilowatt-hours generated during a responding event.
"Paired" means an energy storage system is charged with
electricity generated by a distribution generation device or
community renewable generation project.
"Program" means the stand-alone energy storage
distribution deployment program.
"Scheduled event" means a time period communicated by the
interconnecting electric utility to the stand-alone storage
system under the terms of this Section not less than six hours
in advance, lasting not more than four total hours (whether or

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not consecutive) on the same day. No less than [40] and more
than [50] scheduled events may occur per calendar quarter. No
scheduled event may end after 10 p.m. central prevailing time
or begin prior to 2 a.m. central prevailing time.
"Stand-alone energy storage system" means a device
interconnected to the distribution grid of an electric utility
that is not behind the meter of a retail customer and is not
DC-coupled with generation.
"Transmission amount" means the participating capacity of
the stand-alone energy storage system, as measured pursuant to
the terms of this Section, (i) the applicable transmission
price (in $/kW-day) set by the regional transmission
organization, and (ii) the number of days during the
applicable billing cycle.
"Unscheduled event" means a time period communicated by
the interconnecting utility to the stand-alone storage system
under the terms of this Section not less than 30 minutes in
advance.
(b) The General Assembly finds that stand-alone energy
storage systems interconnected to the distribution grid but
not interconnected behind a customer meter can provide unique
values and benefits to electric ratepayers in Illinois. The
General Assembly further finds that the stand-alone energy
storage systems convey additional value when deployed in
equity investment eligible communities, which will benefit
from property taxes, jobs, and relief to the local

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distribution system. The General Assembly further finds that a
well-designed stand-alone energy storage system program can
reduce the cost to serve all customers, including but not
limited to relieving stress on the distribution system,
lowering the cost of energy and capacity, and reducing
reliance on higher-polluting peaker plants.
(c) Within 120 days after the effective date of this
amendatory Act of the 104th General Assembly, each electric
utility serving at least 200,000 customers as of January 1,
2024 shall file a stand-alone energy storage system program
tariff with the following terms:
(1) Any stand-alone energy storage system with an
aggregate inverter nameplate capacity of less than or
equal to 5,000 kilowatts that is not owned or operated by
the interconnecting electric utility may participate. The
tariff shall not contain a limitation on total
participation.
(2) Each stand-alone energy storage system shall be
considered a retail customer of the interconnecting
utility. Notwithstanding any other provision of this Act
or utility practice, the billing cycle for each such
customer shall be the first to the final day of one
calendar month.
(3) An owner or operator of a stand-alone energy
storage system may designate or re-designate the
participating capacity of a participating system not more

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than one time per calendar year.
(4) Imports shall be charged the following amounts:
(A) A rate per kilowatt-hour equal to the
day-ahead locational marginal price for the utility
zone of the applicable regional transmission
organization at the time of import;
(B) A rate per kilowatt-hour for distribution
charges equal to the per kilowatt-hour charges
applicable to the dusk-to-dawn lighting class of the
applicable utility; and
(C) Taxes and other fees applicable to the
dusk-to-dawn lighting class of the applicable utility.
The utility shall not apply any other charges to imports,
including any demand-based distribution charges. If charges
for imports exceed payments for exports during a billing
cycle, the utility shall issue a bill to the owner of the
stand-alone energy storage system on the same terms and
conditions as bills are sent to retail customers for utility
charges under such utilities tariffs.
(5) Exports shall be paid at the following amounts:
(A) A rate per kilowatt-hour equal to the
day-ahead locational marginal price for the utility
zone of the applicable regional transmission
organization at the time of export;
(B) A fixed amount per quarter equal to: (i) the
sum of the capacity amount and the transmission amount

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for the previous quarter; multiplied by (ii) the ratio
to the number of responding events to scheduled
events, not to exceed 1.00; and
(C) Additional compensation for unscheduled
events, as described in the tariff.
The utility shall not apply other payments to exports
unless approved by the Commission. If the payment for exports
exceeds the charges for imports during a billing cycle, the
utility shall make a payment by wire transfer or automated
clearing house, or other electronic payment to an account
designated by the system owner.
(6) If the sum of the capacity amount and the
transmission amount is zero during a billing cycle, the
stand-alone energy storage device shall receive no payment
for exports other than the day-ahead locational marginal
price for the utility zone of the applicable regional
transmission organization at the time of export.
(7) Events.
(A) Not later than July 1 of each year, each
electric utility shall propose four-hour periods for
each non-holiday weekday during each calendar quarter
the following calendar year. The electric utility
shall set such four-hour periods to meet the electric
utility's then-estimate of the four-hour window most
likely to coincide with daily coincident peak during
the specified quarter. The four-hour periods shall be

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submitted as an informational sheet to the tariff
described in this subsection (c). These four-hour
windows shall be the times for scheduled events.
(B) If an electric utility reasonably believes
that an hour outside the four-hour scheduled event
windows is likely to be the electric utility's
coincident peak for purposes of assessing peak load
capacity or network system peak load under the
utility's tariffs with the applicable regional
transmission organization, on not less than 30 minutes
notice the electric utility shall call an unscheduled
event for that hour.
(8) A method of communication between each
participating stand-alone energy storage system or its
designee and the utility to communicate scheduled events
and unscheduled events.
(9) Terms and conditions of data accessible to the
stand-alone energy storage system or its designee,
including but not limited to performance during scheduled
events during a calendar quarter and applicable capacity
amount and transmission amount.
(10) A procedure for dispute resolution regarding
measurement of the meter or regarding any right or
obligation of either the interconnecting electric utility
or the stand-alone storage system.
(d) The Commission shall approve, with modifications as

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necessary to conform to this Section, such tariff within 240
days after the utility's filing.
(e) Within 120 days of the effective date of this
amendatory Act of the 104th General Assembly, each electric
utility serving at least 200,000 customers as of January 1,
2024 shall either (1) file with the federal energy regulatory
commission a modification of its tariffs with the applicable
regional transmission organization to allow a negative peak
load contribution and negative network system peak load
calculation for a retail customer if (and to the extent that)
such retail customer is a net exporter of power and energy
during the time period(s) during which peak load contributions
and network system peak loads are calculated; or (2) file a
notice concurrent with the tariff identified in subsection (b)
of this Section that such tariff is already in place with the
applicable regional transmission organization.
(f) Each participating electric utility shall be entitled
to recover its reasonable and prudent costs incurred to
administer the stand-alone energy storage program through the
multi-year rate plan identified in Section 16-108.18 of this
Act.
(g) Nothing prohibits a stand-alone energy storage system
taking service under the tariff described in subsection (c) of
this Section from also receiving a smart inverter rebate
described in subsection (c) of Section 16-107.6 of this Act.
The compensation and charges described in paragraphs (2) and

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(3) of subsection (c) of this Section shall neither increase
nor decrease due to receipt of a smart inverter rebate by the
stand-alone energy storage system.
(h) Nothing prohibits an electric utility from applying
the negative peak load contribution of a stand-alone energy
storage device participating under the tariff described in
subsection (c) of this Section towards the utility's peak load
reduction performance metric authorized by item (ii) of
subparagraph (A) of paragraph (2) of subsection (e) of Section
16-108.18.
(i) To the extent that wholesale credit and load
obligation reductions does not completely offset the cost of
providing payment to stand-alone energy storage systems under
the tariff described in this Section, the electric utility
shall recover the remaining costs through its Multi-Year Rate
Plan or, if the electric utility does not have a Multi-Year
Rate Plan, a general request for a rate increase under Section
9-201 of this Act.
(j) Participation in the program shall not prohibit an
energy storage system from selling non-duplicative products
and services in a wholesale market.
(220 ILCS 5/16-108)
Sec. 16-108. Recovery of costs associated with the
provision of delivery and other services.
(a) An electric utility shall file a delivery services

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tariff with the Commission at least 210 days prior to the date
that it is required to begin offering such services pursuant
to this Act. An electric utility shall provide the components
of delivery services that are subject to the jurisdiction of
the Federal Energy Regulatory Commission at the same prices,
terms and conditions set forth in its applicable tariff as
approved or allowed into effect by that Commission. The
Commission shall otherwise have the authority pursuant to
Article IX to review, approve, and modify the prices, terms
and conditions of those components of delivery services not
subject to the jurisdiction of the Federal Energy Regulatory
Commission, including the authority to determine the extent to
which such delivery services should be offered on an unbundled
basis. In making any such determination the Commission shall
consider, at a minimum, the effect of additional unbundling on
(i) the objective of just and reasonable rates, (ii) electric
utility employees, and (iii) the development of competitive
markets for electric energy services in Illinois.
(b) The Commission shall enter an order approving, or
approving as modified, the delivery services tariff no later
than 30 days prior to the date on which the electric utility
must commence offering such services. The Commission may
subsequently modify such tariff pursuant to this Act.
(c) The electric utility's tariffs shall define the
classes of its customers for purposes of delivery services
charges. Delivery services shall be priced and made available

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to all retail customers electing delivery services in each
such class on a nondiscriminatory basis regardless of whether
the retail customer chooses the electric utility, an affiliate
of the electric utility, or another entity as its supplier of
electric power and energy. Charges for delivery services shall
be cost based, and shall allow the electric utility to recover
the costs of providing delivery services through its charges
to its delivery service customers that use the facilities and
services associated with such costs. Such costs shall include
the costs of owning, operating and maintaining transmission
and distribution facilities. The Commission shall also be
authorized to consider whether, and if so to what extent, the
following costs are appropriately included in the electric
utility's delivery services rates: (i) the costs of that
portion of generation facilities used for the production and
absorption of reactive power in order that retail customers
located in the electric utility's service area can receive
electric power and energy from suppliers other than the
electric utility, and (ii) the costs associated with the use
and redispatch of generation facilities to mitigate
constraints on the transmission or distribution system in
order that retail customers located in the electric utility's
service area can receive electric power and energy from
suppliers other than the electric utility. Nothing in this
subsection shall be construed as directing the Commission to
allocate any of the costs described in (i) or (ii) that are

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found to be appropriately included in the electric utility's
delivery services rates to any particular customer group or
geographic area in setting delivery services rates.
(d) The Commission shall establish charges, terms and
conditions for delivery services that are just and reasonable
and shall take into account customer impacts when establishing
such charges. In establishing charges, terms and conditions
for delivery services, the Commission shall take into account
voltage level differences. A retail customer shall have the
option to request to purchase electric service at any delivery
service voltage reasonably and technically feasible from the
electric facilities serving that customer's premises provided
that there are no significant adverse impacts upon system
reliability or system efficiency. A retail customer shall also
have the option to request to purchase electric service at any
point of delivery that is reasonably and technically feasible
provided that there are no significant adverse impacts on
system reliability or efficiency. Such requests shall not be
unreasonably denied.
(e) Electric utilities shall recover the costs of
installing, operating or maintaining facilities for the
particular benefit of one or more delivery services customers,
including without limitation any costs incurred in complying
with a customer's request to be served at a different voltage
level, directly from the retail customer or customers for
whose benefit the costs were incurred, to the extent such

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costs are not recovered through the charges referred to in
subsections (c) and (d) of this Section.
(f) An electric utility shall be entitled but not required
to implement transition charges in conjunction with the
offering of delivery services pursuant to Section 16-104. If
an electric utility implements transition charges, it shall
implement such charges for all delivery services customers and
for all customers described in subsection (h), but shall not
implement transition charges for power and energy that a
retail customer takes from cogeneration or self-generation
facilities located on that retail customer's premises, if such
facilities meet the following criteria:
(i) the cogeneration or self-generation facilities
serve a single retail customer and are located on that
retail customer's premises (for purposes of this
subparagraph and subparagraph (ii), an industrial or
manufacturing retail customer and a third party contractor
that is served by such industrial or manufacturing
customer through such retail customer's own electrical
distribution facilities under the circumstances described
in subsection (vi) of the definition of "alternative
retail electric supplier" set forth in Section 16-102,
shall be considered a single retail customer);
(ii) the cogeneration or self-generation facilities
either (A) are sized pursuant to generally accepted
engineering standards for the retail customer's electrical

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load at that premises (taking into account standby or
other reliability considerations related to that retail
customer's operations at that site) or (B) if the facility
is a cogeneration facility located on the retail
customer's premises, the retail customer is the thermal
host for that facility and the facility has been designed
to meet that retail customer's thermal energy requirements
resulting in electrical output beyond that retail
customer's electrical demand at that premises, comply with
the operating and efficiency standards applicable to
"qualifying facilities" specified in title 18 Code of
Federal Regulations Section 292.205 as in effect on the
effective date of this amendatory Act of 1999;
(iii) the retail customer on whose premises the
facilities are located either has an exclusive right to
receive, and corresponding obligation to pay for, all of
the electrical capacity of the facility, or in the case of
a cogeneration facility that has been designed to meet the
retail customer's thermal energy requirements at that
premises, an identified amount of the electrical capacity
of the facility, over a minimum 5-year period; and
(iv) if the cogeneration facility is sized for the
retail customer's thermal load at that premises but
exceeds the electrical load, any sales of excess power or
energy are made only at wholesale, are subject to the
jurisdiction of the Federal Energy Regulatory Commission,

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and are not for the purpose of circumventing the
provisions of this subsection (f).
If a generation facility located at a retail customer's
premises does not meet the above criteria, an electric utility
implementing transition charges shall implement a transition
charge until December 31, 2006 for any power and energy taken
by such retail customer from such facility as if such power and
energy had been delivered by the electric utility. Provided,
however, that an industrial retail customer that is taking
power from a generation facility that does not meet the above
criteria but that is located on such customer's premises will
not be subject to a transition charge for the power and energy
taken by such retail customer from such generation facility if
the facility does not serve any other retail customer and
either was installed on behalf of the customer and for its own
use prior to January 1, 1997, or is both predominantly fueled
by byproducts of such customer's manufacturing process at such
premises and sells or offers an average of 300 megawatts or
more of electricity produced from such generation facility
into the wholesale market. Such charges shall be calculated as
provided in Section 16-102, and shall be collected on each
kilowatt-hour delivered under a delivery services tariff to a
retail customer from the date the customer first takes
delivery services until December 31, 2006 except as provided
in subsection (h) of this Section. Provided, however, that an
electric utility, other than an electric utility providing

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service to at least 1,000,000 customers in this State on
January 1, 1999, shall be entitled to petition for entry of an
order by the Commission authorizing the electric utility to
implement transition charges for an additional period ending
no later than December 31, 2008. The electric utility shall
file its petition with supporting evidence no earlier than 16
months, and no later than 12 months, prior to December 31,
2006. The Commission shall hold a hearing on the electric
utility's petition and shall enter its order no later than 8
months after the petition is filed. The Commission shall
determine whether and to what extent the electric utility
shall be authorized to implement transition charges for an
additional period. The Commission may authorize the electric
utility to implement transition charges for some or all of the
additional period, and shall determine the mitigation factors
to be used in implementing such transition charges; provided,
that the Commission shall not authorize mitigation factors
less than 110% of those in effect during the 12 months ended
December 31, 2006. In making its determination, the Commission
shall consider the following factors: the necessity to
implement transition charges for an additional period in order
to maintain the financial integrity of the electric utility;
the prudence of the electric utility's actions in reducing its
costs since the effective date of this amendatory Act of 1997;
the ability of the electric utility to provide safe, adequate
and reliable service to retail customers in its service area;

HB3758 - 340 - LRB104 12225 JDS 22331 b
and the impact on competition of allowing the electric utility
to implement transition charges for the additional period.
(g) The electric utility shall file tariffs that establish
the transition charges to be paid by each class of customers to
the electric utility in conjunction with the provision of
delivery services. The electric utility's tariffs shall define
the classes of its customers for purposes of calculating
transition charges. The electric utility's tariffs shall
provide for the calculation of transition charges on a
customer-specific basis for any retail customer whose average
monthly maximum electrical demand on the electric utility's
system during the 6 months with the customer's highest monthly
maximum electrical demands equals or exceeds 3.0 megawatts for
electric utilities having more than 1,000,000 customers, and
for other electric utilities for any customer that has an
average monthly maximum electrical demand on the electric
utility's system of one megawatt or more, and (A) for which
there exists data on the customer's usage during the 3 years
preceding the date that the customer became eligible to take
delivery services, or (B) for which there does not exist data
on the customer's usage during the 3 years preceding the date
that the customer became eligible to take delivery services,
if in the electric utility's reasonable judgment there exists
comparable usage information or a sufficient basis to develop
such information, and further provided that the electric
utility can require customers for which an individual

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calculation is made to sign contracts that set forth the
transition charges to be paid by the customer to the electric
utility pursuant to the tariff.
(h) An electric utility shall also be entitled to file
tariffs that allow it to collect transition charges from
retail customers in the electric utility's service area that
do not take delivery services but that take electric power or
energy from an alternative retail electric supplier or from an
electric utility other than the electric utility in whose
service area the customer is located. Such charges shall be
calculated, in accordance with the definition of transition
charges in Section 16-102, for the period of time that the
customer would be obligated to pay transition charges if it
were taking delivery services, except that no deduction for
delivery services revenues shall be made in such calculation,
and usage data from the customer's class shall be used where
historical usage data is not available for the individual
customer. The customer shall be obligated to pay such charges
on a lump sum basis on or before the date on which the customer
commences to take service from the alternative retail electric
supplier or other electric utility, provided, that the
electric utility in whose service area the customer is located
shall offer the customer the option of signing a contract
pursuant to which the customer pays such charges ratably over
the period in which the charges would otherwise have applied.
(i) An electric utility shall be entitled to add to the

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bills of delivery services customers charges pursuant to
Sections 9-221, 9-222 (except as provided in Section 9-222.1),
and Section 16-114 of this Act, Section 5-5 of the Electricity
Infrastructure Maintenance Fee Law, Section 6-5 of the
Renewable Energy, Energy Efficiency, and Coal Resources
Development Law of 1997, and Section 13 of the Energy
Assistance Act.
(i-5) An electric utility required to impose the Coal to
Solar and Energy Storage Initiative Charge provided for in
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act shall add such charge to the bills of its delivery services
customers pursuant to the terms of a tariff conforming to the
requirements of subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act and this subsection (i-5) and filed
with and approved by the Commission. The electric utility
shall file its proposed tariff with the Commission on or
before July 1, 2022 to be effective, after review and approval
or modification by the Commission, beginning January 1, 2023.
On or before December 1, 2022, the Commission shall review the
electric utility's proposed tariff, including by conducting a
docketed proceeding if deemed necessary by the Commission, and
shall approve the proposed tariff or direct the electric
utility to make modifications the Commission finds necessary
for the tariff to conform to the requirements of subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act and this
subsection (i-5). The electric utility's tariff shall provide

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for imposition of the Coal to Solar and Energy Storage
Initiative Charge on a per-kilowatthour basis to all
kilowatthours delivered by the electric utility to its
delivery services customers. The tariff shall provide for the
calculation of the Coal to Solar and Energy Storage Initiative
Charge to be in effect for the year beginning January 1, 2023
and each year beginning January 1 thereafter, sufficient to
collect the electric utility's estimated payment obligations
for the delivery year beginning the following June 1 under
contracts for purchase of renewable energy credits entered
into pursuant to subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act and the obligations of the
Department of Commerce and Economic Opportunity, or any
successor department or agency, which for purposes of this
subsection (i-5) shall be referred to as the Department, to
make grant payments during such delivery year from the Coal to
Solar and Energy Storage Initiative Fund pursuant to grant
contracts entered into pursuant to subsection (c-5) of Section
1-75 of the Illinois Power Agency Act, and using the electric
utility's kilowatthour deliveries to its delivery services
customers during the delivery year ended May 31 of the
preceding calendar year. On or before November 1 of each year
beginning November 1, 2022, the Department shall notify the
electric utilities of the amount of the Department's estimated
obligations for grant payments during the delivery year
beginning the following June 1 pursuant to grant contracts

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entered into pursuant to subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act; and each electric utility shall
incorporate in the calculation of its Coal to Solar and Energy
Storage Initiative Charge the fractional portion of the
Department's estimated obligations equal to the electric
utility's kilowatthour deliveries to its delivery services
customers in the delivery year ended the preceding May 31
divided by the aggregate deliveries of both electric utilities
to delivery services customers in such delivery year. The
electric utility shall remit on a monthly basis to the State
Treasurer, for deposit in the Coal to Solar and Energy Storage
Initiative Fund provided for in subsection (c-5) of Section
1-75 of the Illinois Power Agency Act, the electric utility's
collections of the Coal to Solar and Energy Storage Initiative
Charge estimated to be needed by the Department for grant
payments pursuant to grant contracts entered into pursuant to
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act. The initial charge under the electric utility's tariff
shall be effective for kilowatthours delivered beginning
January 1, 2023, and thereafter shall be revised to be
effective January 1, 2024 and each January 1 thereafter, based
on the payment obligations for the delivery year beginning the
following June 1. The tariff shall provide for the electric
utility to make an annual filing with the Commission on or
before November 15 of each year, beginning in 2023, setting
forth the Coal to Solar and Energy Storage Initiative Charge

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to be in effect for the year beginning the following January 1.
The electric utility's tariff shall also provide that the
electric utility shall make a filing with the Commission on or
before August 1 of each year beginning in 2024 setting forth a
reconciliation, for the delivery year ended the preceding May
31, of the electric utility's collections of the Coal to Solar
and Energy Storage Initiative Charge against actual payments
for renewable energy credits pursuant to contracts entered
into, and the actual grant payments by the Department pursuant
to grant contracts entered into, pursuant to subsection (c-5)
of Section 1-75 of the Illinois Power Agency Act. The tariff
shall provide that any excess or shortfall of collections to
payments shall be deducted from or added to, on a
per-kilowatthour basis, the Coal to Solar and Energy Storage
Initiative Charge, over the 6-month period beginning October 1
of that calendar year.
(j) If a retail customer that obtains electric power and
energy from cogeneration or self-generation facilities
installed for its own use on or before January 1, 1997,
subsequently takes service from an alternative retail electric
supplier or an electric utility other than the electric
utility in whose service area the customer is located for any
portion of the customer's electric power and energy
requirements formerly obtained from those facilities
(including that amount purchased from the utility in lieu of
such generation and not as standby power purchases, under a

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cogeneration displacement tariff in effect as of the effective
date of this amendatory Act of 1997), the transition charges
otherwise applicable pursuant to subsections (f), (g), or (h)
of this Section shall not be applicable in any year to that
portion of the customer's electric power and energy
requirements formerly obtained from those facilities,
provided, that for purposes of this subsection (j), such
portion shall not exceed the average number of kilowatt-hours
per year obtained from the cogeneration or self-generation
facilities during the 3 years prior to the date on which the
customer became eligible for delivery services, except as
provided in subsection (f) of Section 16-110.
(k) The electric utility shall be entitled to recover
through tariffed charges all of the costs associated with the
purchase of zero emission credits from zero emission
facilities to meet the requirements of subsection (d-5) of
Section 1-75 of the Illinois Power Agency Act and all of the
costs associated with the purchase of carbon mitigation
credits from carbon-free energy resources to meet the
requirements of subsection (d-10) of Section 1-75 of the
Illinois Power Agency Act. Such costs shall include the costs
of procuring the zero emission credits and carbon mitigation
credits from carbon-free energy resources, as well as the
reasonable costs that the utility incurs as part of the
procurement processes and to implement and comply with plans
and processes approved by the Commission under subsections

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(d-5) and (d-10). The costs shall be allocated across all
retail customers through a single, uniform cents per
kilowatt-hour charge applicable to all retail customers, which
shall appear as a separate line item on each customer's bill.
Beginning June 1, 2017, the electric utility shall be entitled
to recover through tariffed charges all of the costs
associated with the purchase of renewable energy resources to
meet the renewable energy resource standards of subsection (c)
of Section 1-75 of the Illinois Power Agency Act, under
procurement plans as approved in accordance with that Section
and Section 16-111.5 of this Act. Such costs shall include the
costs of procuring the renewable energy resources, as well as
the reasonable costs that the utility incurs as part of the
procurement processes and to implement and comply with plans
and processes approved by the Commission under such Sections.
The costs associated with the purchase of renewable energy
resources shall be allocated across all retail customers in
proportion to the amount of renewable energy resources the
utility procures for such customers through a single, uniform
cents per kilowatt-hour charge applicable to such retail
customers, which shall appear as a separate line item on each
such customer's bill. The credits, costs, and penalties
associated with the self-direct renewable portfolio standard
compliance program described in subparagraph (R) of paragraph
(1) of subsection (c) of Section 1-75 of the Illinois Power
Agency Act shall be allocated to approved eligible self-direct

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customers by the utility in a cents per kilowatt-hour credit,
cost, or penalty, which shall appear as a separate line item on
each such customer's bill.
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
the energy storage standards of Section 1-93 of the Illinois
Power Agency Act under procurement plans approved in
accordance with that Section and Section 16-111.5. The costs
shall include the costs of procuring the energy storage
credits and the reasonable costs that the utility incurs as
part of the procurement processes and implementing and
complying with plans and processes approved by the Commission.
The costs associated with the purchase of energy storage
credits shall be allocated across all retail customers in
proportion to the amount of energy storage credits the
electric utility procures for the customers through a single,
uniform cents per kilowatt-hour charge applicable to the
retail customers, that shall appear as a separate line item on
each customer's bill.
Notwithstanding whether the Commission has approved the
initial long-term renewable resources procurement plan as of
June 1, 2017, an electric utility shall place new tariffed
charges into effect beginning with the June 2017 monthly
billing period, to the extent practicable, to begin recovering
the costs of procuring renewable energy resources, as those

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charges are calculated under the limitations described in
subparagraph (E) of paragraph (1) of subsection (c) of Section
1-75 of the Illinois Power Agency Act. Notwithstanding the
date on which the utility places such new tariffed charges
into effect, the utility shall be permitted to collect the
charges under such tariff as if the tariff had been in effect
beginning with the first day of the June 2017 monthly billing
period. For the delivery years commencing June 1, 2017, June
1, 2018, June 1, 2019, and each delivery year thereafter, the
electric utility shall deposit into a separate interest
bearing account of a financial institution the monies
collected under the tariffed charges. Money collected from
customers for the procurement of renewable energy resources in
a given delivery year may be spent by the utility for the
procurement of renewable resources over any of the following 5
delivery years, after which unspent money shall be credited
back to retail customers. The electric utility shall spend all
money collected in earlier delivery years that has not yet
been returned to customers, first, before spending money
collected in later delivery years. Any interest earned shall
be credited back to retail customers under the reconciliation
proceeding provided for in this subsection (k), provided that
the electric utility shall first be reimbursed from the
interest for the administrative costs that it incurs to
administer and manage the account. Any taxes due on the funds
in the account, or interest earned on it, will be paid from the

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account or, if insufficient monies are available in the
account, from the monies collected under the tariffed charges
to recover the costs of procuring renewable energy resources.
Monies deposited in the account shall be subject to the
review, reconciliation, and true-up process described in this
subsection (k) that is applicable to the funds collected and
costs incurred for the procurement of renewable energy
resources.
The electric utility shall be entitled to recover all of
the costs identified in this subsection (k) through automatic
adjustment clause tariffs applicable to all of the utility's
retail customers that allow the electric utility to adjust its
tariffed charges consistent with this subsection (k). The
determination as to whether any excess funds were collected
during a given delivery year for the purchase of renewable
energy resources, and the crediting of any excess funds back
to retail customers, shall not be made until after the close of
the delivery year, which will ensure that the maximum amount
of funds is available to implement the approved long-term
renewable resources procurement plan during a given delivery
year. The amount of excess funds eligible to be credited back
to retail customers shall be reduced by an amount equal to the
payment obligations required by any contracts entered into by
an electric utility under contracts described in subsection
(b) of Section 1-56 and subsection (c) of Section 1-75 of the
Illinois Power Agency Act, even if such payments have not yet

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been made and regardless of the delivery year in which those
payment obligations were incurred. Notwithstanding anything to
the contrary, including in tariffs authorized by this
subsection (k) in effect before the effective date of this
amendatory Act of the 102nd General Assembly, all unspent
funds as of May 31, 2021, excluding any funds credited to
customers during any utility billing cycle that commences
prior to the effective date of this amendatory Act of the 102nd
General Assembly, shall remain in the utility account and
shall on a first in, first out basis be used toward utility
payment obligations under contracts described in subsection
(b) of Section 1-56 and subsection (c) of Section 1-75 of the
Illinois Power Agency Act. The electric utility's collections
under such automatic adjustment clause tariffs to recover the
costs of renewable energy resources, zero emission credits
from zero emission facilities, and carbon mitigation credits
from carbon-free energy resources shall be subject to separate
annual review, reconciliation, and true-up against actual
costs by the Commission under a procedure that shall be
specified in the electric utility's automatic adjustment
clause tariffs and that shall be approved by the Commission in
connection with its approval of such tariffs. The procedure
shall provide that any difference between the electric
utility's collections for zero emission credits and carbon
mitigation credits under the automatic adjustment charges for
an annual period and the electric utility's actual costs of

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zero emission credits from zero emission facilities and carbon
mitigation credits from carbon-free energy resources for that
same annual period shall be refunded to or collected from, as
applicable, the electric utility's retail customers in
subsequent periods.
Nothing in this subsection (k) is intended to affect,
limit, or change the right of the electric utility to recover
the costs associated with the procurement of renewable energy
resources for periods commencing before, on, or after June 1,
2017, as otherwise provided in the Illinois Power Agency Act.
The funding available under this subsection (k), if any,
for the programs described under subsection (b) of Section
1-56 of the Illinois Power Agency Act shall not reduce the
amount of funding for the programs described in subparagraph
(O) of paragraph (1) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act. If funding is available under this
subsection (k) for programs described under subsection (b) of
Section 1-56 of the Illinois Power Agency Act, then the
long-term renewable resources plan shall provide for the
Agency to procure contracts in an amount that does not exceed
the funding, and the contracts approved by the Commission
shall be executed by the applicable utility or utilities.
(l) A utility that has terminated any contract executed
under subsection (d-5) or (d-10) of Section 1-75 of the
Illinois Power Agency Act shall be entitled to recover any
remaining balance associated with the purchase of zero

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emission credits prior to such termination, and such utility
shall also apply a credit to its retail customer bills in the
event of any over-collection.
(m)(1) An electric utility that recovers its costs of
procuring zero emission credits from zero emission facilities
through a cents-per-kilowatthour charge under subsection (k)
of this Section shall be subject to the requirements of this
subsection (m). Notwithstanding anything to the contrary, such
electric utility shall, beginning on April 30, 2018, and each
April 30 thereafter until April 30, 2026, calculate whether
any reduction must be applied to such cents-per-kilowatthour
charge that is paid by retail customers of the electric
utility that have opted out of subsections (a) through (j) of
Section 8-103B of this Act under subsection (l) of Section
8-103B. Such charge shall be reduced for such customers for
the next delivery year commencing on June 1 based on the amount
necessary, if any, to limit the annual estimated average net
increase for the prior calendar year due to the future energy
investment costs to no more than 1.3% of 5.98 cents per
kilowatt-hour, which is the average amount paid per
kilowatthour for electric service during the year ending
December 31, 2015 by Illinois industrial retail customers, as
reported to the Edison Electric Institute.
The calculations required by this subsection (m) shall be
made only once for each year, and no subsequent rate impact
determinations shall be made.

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(2) For purposes of this Section, "future energy
investment costs" shall be calculated by subtracting the
cents-per-kilowatthour charge identified in subparagraph (A)
of this paragraph (2) from the sum of the
cents-per-kilowatthour charges identified in subparagraph (B)
of this paragraph (2):
(A) The cents-per-kilowatthour charge identified in
the electric utility's tariff placed into effect under
Section 8-103 of the Public Utilities Act that, on
December 1, 2016, was applicable to those retail customers
that have opted out of subsections (a) through (j) of
Section 8-103B of this Act under subsection (l) of Section
8-103B.
(B) The sum of the following cents-per-kilowatthour
charges applicable to those retail customers that have
opted out of subsections (a) through (j) of Section 8-103B
of this Act under subsection (l) of Section 8-103B,
provided that if one or more of the following charges has
been in effect and applied to such customers for more than
one calendar year, then each charge shall be equal to the
average of the charges applied over a period that
commences with the calendar year ending December 31, 2017
and ends with the most recently completed calendar year
prior to the calculation required by this subsection (m):
(i) the cents-per-kilowatthour charge to recover
the costs incurred by the utility under subsection

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(d-5) of Section 1-75 of the Illinois Power Agency
Act, adjusted for any reductions required under this
subsection (m); and
(ii) the cents-per-kilowatthour charge to recover
the costs incurred by the utility under Section
16-107.6 of the Public Utilities Act.
If no charge was applied for a given calendar year
under item (i) or (ii) of this subparagraph (B), then the
value of the charge for that year shall be zero.
(3) If a reduction is required by the calculation
performed under this subsection (m), then the amount of the
reduction shall be multiplied by the number of years reflected
in the averages calculated under subparagraph (B) of paragraph
(2) of this subsection (m). Such reduction shall be applied to
the cents-per-kilowatthour charge that is applicable to those
retail customers that have opted out of subsections (a)
through (j) of Section 8-103B of this Act under subsection (l)
of Section 8-103B beginning with the next delivery year
commencing after the date of the calculation required by this
subsection (m).
(4) The electric utility shall file a notice with the
Commission on May 1 of 2018 and each May 1 thereafter until May
1, 2026 containing the reduction, if any, which must be
applied for the delivery year which begins in the year of the
filing. The notice shall contain the calculations made
pursuant to this Section. By October 1 of each year beginning

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in 2018, each electric utility shall notify the Commission if
it appears, based on an estimate of the calculation required
in this subsection (m), that a reduction will be required in
the next year.
(Source: P.A. 102-662, eff. 9-15-21.)
(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.
(a) An electric utility that on December 31, 2005 served
at least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with
the applicable provisions set forth in Section 1-75 of the
Illinois Power Agency Act and this Section. Beginning with the
delivery year commencing on June 1, 2024, an electric utility
serving over 100,000 customers in Illinois shall also procure
energy storage credits in accordance with the applicable
provisions of Sections 1-75 and 1-93 of the Illinois Power
Agency Act and this Section. Beginning with the delivery year
commencing on June 1, 2017, such electric utility shall also
procure zero emission credits from zero emission facilities in
accordance with the applicable provisions set forth in Section
1-75 of the Illinois Power Agency Act, and, for years
beginning on or after June 1, 2017, the utility shall procure
renewable energy resources in accordance with the applicable
provisions set forth in Section 1-75 of the Illinois Power
Agency Act and this Section. Beginning with the delivery year

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commencing on June 1, 2022, an electric utility serving over
3,000,000 customers shall also procure carbon mitigation
credits from carbon-free energy resources in accordance with
the applicable provisions set forth in Section 1-75 of the
Illinois Power Agency Act and this Section. A small
multi-jurisdictional electric utility that on December 31,
2005 served less than 100,000 customers in Illinois may elect
to procure power and energy for all or a portion of its
eligible Illinois retail customers in accordance with the
applicable provisions set forth in this Section and Section
1-75 of the Illinois Power Agency Act. This Section shall not
apply to a small multi-jurisdictional utility until such time
as a small multi-jurisdictional utility requests the Illinois
Power Agency to prepare a procurement plan for its eligible
retail customers. "Eligible retail customers" for the purposes
of this Section means those retail customers that purchase
power and energy from the electric utility under fixed-price
bundled service tariffs, other than those retail customers
whose service is declared or deemed competitive under Section
16-113 and those other customer groups specified in this
Section, including self-generating customers, customers
electing hourly pricing, or those customers who are otherwise
ineligible for fixed-price bundled tariff service. For those
customers that are excluded from the procurement plan's
electric supply service requirements, and the utility shall
procure any supply requirements, including capacity, ancillary

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services, and hourly priced energy, in the applicable markets
as needed to serve those customers, provided that the utility
may include in its procurement plan load requirements for the
load that is associated with those retail customers whose
service has been declared or deemed competitive pursuant to
Section 16-113 of this Act to the extent that those customers
are purchasing power and energy during one of the transition
periods identified in subsection (b) of Section 16-113 of this
Act.
(b) A procurement plan shall be prepared for each electric
utility consistent with the applicable requirements of the
Illinois Power Agency Act and this Section. For purposes of
this Section, Illinois electric utilities that are affiliated
by virtue of a common parent company are considered to be a
single electric utility. Small multi-jurisdictional utilities
may request a procurement plan for a portion of or all of its
Illinois load. Each procurement plan shall analyze the
projected balance of supply and demand for those retail
customers to be included in the plan's electric supply service
requirements over a 5-year period, with the first planning
year beginning on June 1 of the year following the year in
which the plan is filed. The plan shall specifically identify
the wholesale products to be procured following plan approval,
and shall follow all the requirements set forth in the Public
Utilities Act and all applicable State and federal laws,
statutes, rules, or regulations, as well as Commission orders.

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Nothing in this Section precludes consideration of contracts
longer than 5 years and related forecast data. Unless
specified otherwise in this Section, in the procurement plan
or in the implementing tariff, any procurement occurring in
accordance with this plan shall be competitively bid through a
request for proposals process. Approval and implementation of
the procurement plan shall be subject to review and approval
by the Commission according to the provisions set forth in
this Section. A procurement plan shall include each of the
following components:
(1) Hourly load analysis. This analysis shall include:
(i) multi-year historical analysis of hourly
loads;
(ii) switching trends and competitive retail
market analysis;
(iii) known or projected changes to future loads;
and
(iv) growth forecasts by customer class; and .
(v) the impact of load reduction and peak load
reduction through programs authorized by Sections
16-107.9, 16-107.10, and 16-107.11.
(2) Analysis of the impact of any demand side and
renewable energy initiatives. This analysis shall include:
(i) the impact of demand response programs and
energy efficiency programs, both current and
projected; for small multi-jurisdictional utilities,

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the impact of demand response and energy efficiency
programs approved pursuant to Section 8-408 of this
Act, both current and projected; and
(ii) supply side needs that are projected to be
offset by purchases of renewable energy resources, if
any.
(3) A plan for meeting the expected load requirements
that will not be met through preexisting contracts. This
plan shall include:
(i) definitions of the different Illinois retail
customer classes for which supply is being purchased;
(ii) the proposed mix of demand-response products
for which contracts will be executed during the next
year. For small multi-jurisdictional electric
utilities that on December 31, 2005 served fewer than
100,000 customers in Illinois, these shall be defined
as demand-response products offered in an energy
efficiency plan approved pursuant to Section 8-408 of
this Act. The cost-effective demand-response measures
shall be procured whenever the cost is lower than
procuring comparable capacity products, provided that
such products shall:
(A) be procured by a demand-response provider
from those retail customers included in the plan's
electric supply service requirements;
(B) at least satisfy the demand-response

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requirements of the regional transmission
organization market in which the utility's service
territory is located, including, but not limited
to, any applicable capacity or dispatch
requirements;
(C) provide for customers' participation in
the stream of benefits produced by the
demand-response products;
(D) provide for reimbursement by the
demand-response provider of the utility for any
costs incurred as a result of the failure of the
supplier of such products to perform its
obligations thereunder; and
(E) meet the same credit requirements as apply
to suppliers of capacity, in the applicable
regional transmission organization market;
(iii) monthly forecasted system supply
requirements, including expected minimum, maximum, and
average values for the planning period;
(iv) the proposed mix and selection of standard
wholesale products for which contracts will be
executed during the next year, separately or in
combination, to meet that portion of its load
requirements not met through pre-existing contracts,
including but not limited to monthly 5 x 16 peak period
block energy, monthly off-peak wrap energy, monthly 7

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x 24 energy, annual 5 x 16 energy, other standardized
energy or capacity products designed to provide
eligible retail customer benefits from commercially
deployed advanced technologies including but not
limited to high voltage direct current converter
stations, as such term is defined in Section 1-10 of
the Illinois Power Agency Act, whether or not such
product is currently available in wholesale markets,
annual off-peak wrap energy, annual 7 x 24 energy,
monthly capacity, annual capacity, peak load capacity
obligations, capacity purchase plan, and ancillary
services;
(v) proposed term structures for each wholesale
product type included in the proposed procurement plan
portfolio of products; and
(vi) an assessment of the price risk, load
uncertainty, and other factors that are associated
with the proposed procurement plan; this assessment,
to the extent possible, shall include an analysis of
the following factors: contract terms, time frames for
securing products or services, fuel costs, weather
patterns, transmission costs, market conditions, and
the governmental regulatory environment; the proposed
procurement plan shall also identify alternatives for
those portfolio measures that are identified as having
significant price risk and mitigation in the form of

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additional retail customer and ratepayer price,
reliability, and environmental benefits from
standardized energy products delivered from
commercially deployed advanced technologies,
including, but not limited to, high voltage direct
current converter stations, as such term is defined in
Section 1-10 of the Illinois Power Agency Act, whether
or not such product is currently available in
wholesale markets.
(4) Proposed procedures for balancing loads. The
procurement plan shall include, for load requirements
included in the procurement plan, the process for (i)
hourly balancing of supply and demand and (ii) the
criteria for portfolio re-balancing in the event of
significant shifts in load.
(5) Long-Term Renewable Resources Procurement Plan.
The Agency shall prepare a long-term renewable resources
procurement plan for the procurement of renewable energy
credits under Sections 1-56 and 1-75 of the Illinois Power
Agency Act for delivery beginning in the 2017 delivery
year.
(i) The initial long-term renewable resources
procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
the purposes of this Section, "delivery year" has the
same meaning as in Section 1-10 of the Illinois Power

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Agency Act. For purposes of this Section, "Agency"
shall mean the Illinois Power Agency.
(ii) The long-term renewable resources planning
process shall be conducted as follows:
(A) Electric utilities shall provide a range
of load forecasts to the Illinois Power Agency
within 45 days of the Agency's request for
forecasts, which request shall specify the length
and conditions for the forecasts including, but
not limited to, the quantity of distributed
generation expected to be interconnected for each
year.
(B) The Agency shall publish for comment the
initial long-term renewable resources procurement
plan no later than 120 days after the effective
date of this amendatory Act of the 99th General
Assembly and shall review, and may revise, the
plan at least every 2 years thereafter. To the
extent practicable, the Agency shall review and
propose any revisions to the long-term renewable
energy resources procurement plan in conjunction
with the Agency's other planning and approval
processes conducted under this Section. The
initial long-term renewable resources procurement
plan shall:
(aa) Identify the procurement programs and

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competitive procurement events consistent with
the applicable requirements of the Illinois
Power Agency Act and shall be designed to
achieve the goals set forth in subsection (c)
of Section 1-75 of that Act.
(bb) Include a schedule for procurements
for renewable energy credits from
utility-scale wind projects, utility-scale
solar projects, and brownfield site
photovoltaic projects consistent with
subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois
Power Agency Act.
(cc) Identify the process whereby the
Agency will submit to the Commission for
review and approval the proposed contracts to
implement the programs required by such plan.
Copies of the initial long-term renewable
resources procurement plan and all subsequent
revisions shall be posted and made publicly
available on the Agency's and Commission's
websites, and copies shall also be provided to
each affected electric utility. An affected
utility and other interested parties shall have 45
days following the date of posting to provide
comment to the Agency on the initial long-term

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renewable resources procurement plan and all
subsequent revisions. All comments submitted to
the Agency shall be specific, supported by data or
other detailed analyses, and, if objecting to all
or a portion of the procurement plan, accompanied
by specific alternative wording or proposals. All
comments shall be posted on the Agency's and
Commission's websites. During this 45-day comment
period, the Agency shall hold at least one public
hearing within each utility's service area that is
subject to the requirements of this paragraph (5)
for the purpose of receiving public comment.
Within 21 days following the end of the 45-day
review period, the Agency may revise the long-term
renewable resources procurement plan based on the
comments received and shall file the plan with the
Commission for review and approval.
(C) Within 14 days after the filing of the
initial long-term renewable resources procurement
plan or any subsequent revisions, any person
objecting to the plan may file an objection with
the Commission. Within 21 days after the filing of
the plan, the Commission shall determine whether a
hearing is necessary. The Commission shall enter
its order confirming or modifying the initial
long-term renewable resources procurement plan or

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any subsequent revisions within 120 days after the
filing of the plan by the Illinois Power Agency.
(D) The Commission shall approve the initial
long-term renewable resources procurement plan and
any subsequent revisions, including expressly the
forecast used in the plan and taking into account
that funding will be limited to the amount of
revenues actually collected by the utilities, if
the Commission determines that the plan will
reasonably and prudently accomplish the
requirements of Section 1-56 and subsection (c) of
Section 1-75 of the Illinois Power Agency Act. The
Commission shall also approve the process for the
submission, review, and approval of the proposed
contracts to procure renewable energy credits or
implement the programs authorized by the
Commission pursuant to a long-term renewable
resources procurement plan approved under this
Section.
In approving any long-term renewable resources
procurement plan after the effective date of this
amendatory Act of the 102nd General Assembly, the
Commission shall approve or modify the Agency's
proposal for minimum equity standards pursuant to
subsection (c-10) of Section 1-75 of the Illinois
Power Agency Act. The Commission shall consider

HB3758 - 368 - LRB104 12225 JDS 22331 b
any analysis performed by the Agency in developing
its proposal, including past performance,
availability of equity eligible contractors, and
availability of equity eligible persons at the
time the long-term renewable resources procurement
plan is approved.
(iii) The Agency or third parties contracted by
the Agency shall implement all programs authorized by
the Commission in an approved long-term renewable
resources procurement plan without further review and
approval by the Commission. Third parties shall not
begin implementing any programs or receive any payment
under this Section until the Commission has approved
the contract or contracts under the process authorized
by the Commission in item (D) of subparagraph (ii) of
paragraph (5) of this subsection (b) and the third
party and the Agency or utility, as applicable, have
executed the contract. For those renewable energy
credits subject to procurement through a competitive
bid process under the plan or under the initial
forward procurements for wind and solar resources
described in subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois Power
Agency Act, the Agency shall follow the procurement
process specified in the provisions relating to
electricity procurement in subsections (e) through (i)

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of this Section.
(iv) An electric utility shall recover its costs
associated with the procurement of renewable energy
credits under this Section and pursuant to subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act
through an automatic adjustment clause tariff under
subsection (k) or a tariff pursuant to subsection
(i-5), as applicable, of Section 16-108 of this Act. A
utility shall not be required to advance any payment
or pay any amounts under this Section that exceed the
actual amount of revenues collected by the utility
under paragraph (6) of subsection (c) of Section 1-75
of the Illinois Power Agency Act, subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act, and
subsection (k) or subsection (i-5), as applicable, of
Section 16-108 of this Act, and contracts executed
under this Section shall expressly incorporate this
limitation.
(v) For the public interest, safety, and welfare,
the Agency and the Commission may adopt rules to carry
out the provisions of this Section on an emergency
basis immediately following the effective date of this
amendatory Act of the 99th General Assembly.
(vi) On or before July 1 of each year, the
Commission shall hold an informal hearing for the
purpose of receiving comments on the prior year's

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procurement process and any recommendations for
change.
(6) Long-term energy storage resources procurement
plan. The Agency shall prepare an energy storage resources
procurement plan for the procurement of energy storage
credits in compliance with this Section and Section 1-93
of the Illinois Power Agency Act.
(i) The initial energy storage resources
procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
purposes of this Section, "delivery year" has the same
meaning as used in Section 1-10 of the Illinois Power
Agency Act. In this paragraph, "Agency" means the
Illinois Power Agency.
(ii) The energy storage resources planning process
shall be conducted as follows:
(A) The Agency shall publish for comment the
initial energy storage resources procurement plan
no later than 180 days after the effective date of
this amendatory Act of the 104th General Assembly
and shall review and may revise the plan at least
every 2 years thereafter. To the extent
practicable, the Agency shall review and propose
any revisions to the energy storage resources
procurement plan in conjunction with the Agency's
other planning and approval processes conducted

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under this Section. The initial energy storage
resources procurement plan shall:
(aa) include a schedule for procurements
for energy storage credits from qualified
energy storage systems consistent with Section
1-93 of the Illinois Power Agency Act,
including proposals for allocation between
indexed credits and tolling agreements;
(bb) identify the process whereby the
Agency will submit to the Commission for
review and approval the proposed contracts to
implement the programs required by the plan.
Copies of the initial energy storage resources
procurement plan and all subsequent revisions
shall be posted and made publicly available on
the Agency's and Commission's websites, and
copies shall also be provided to each affected
electric utility. An affected utility and
other interested parties shall have 45 days
following the date of posting to provide
comment to the Agency on the initial energy
storage resources procurement plan and all
subsequent revisions. All comments shall be
posted on the Agency's and Commission's
websites; and
(cc) upon solicitation from stakeholders,

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consider additional procurement approaches
that would result in the electric utilities
contracting for energy storage to achieve the
requirements described in subsection (a); and
(B) The Commission shall approve the initial
energy storage resources procurement plan and any
subsequent revisions if the Commission determines
that the plan will reasonably and prudently
accomplish the requirements of Section 1-93 of the
Illinois Power Agency Act. The Commission shall
also approve the process for the submission,
review, and approval of the proposed contracts to
procure energy storage credits or implement the
programs authorized by the Commission pursuant to
a long-term energy storage resources procurement
plan approved under this Section.
In approving any long-term energy storage
procurement plan after the effective date of this
amendatory Act of the 104th General Assembly, the
Commission shall approve or modify the Agency's
proposal for minimum equity standards under
subsection (c-10) of Section 1-75 of the Illinois
Power Agency Act. The Commission shall consider
any analysis performed by the Agency in developing
its proposal, including past performance,
availability of equity eligible contractors, and

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availability of equity eligible persons at the
time the long-term renewable resources procurement
plan is approved.
(iii) The Agency or third parties contracted by
the Agency shall implement all programs authorized by
the Commission in an approved long-term energy storage
procurement plan without further review and approval
by the Commission. Third parties shall not begin
implementing any programs or receive any payment under
this Section until the Commission has approved the
long-term storage contract.
(iv) An electric utility shall recover its costs
associated with the procurement of energy storage
credits under this Section and pursuant to Section
1-93 of the Illinois Power Agency Act through an
automatic adjustment clause tariff under subsection
(k) or a tariff under subsection (i-5), as applicable,
of Section 16-108.
(b-5) An electric utility that as of January 1, 2019
served more than 300,000 retail customers in this State shall
purchase renewable energy credits from new renewable energy
facilities constructed at or adjacent to the sites of
coal-fueled electric generating facilities in this State in
accordance with subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act. Except as expressly provided in
this Section, the plans and procedures for such procurements

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shall not be included in the procurement plans provided for in
this Section, but rather shall be conducted and implemented
solely in accordance with subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act.
(c) The provisions of this subsection (c) shall not apply
to procurements conducted pursuant to subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act. However, the
Agency may retain a procurement administrator to assist the
Agency in planning and carrying out the procurement events and
implementing the other requirements specified in such
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act, with the costs incurred by the Agency for the procurement
administrator to be recovered through fees charged to
applicants for selection to sell and deliver renewable energy
credits to electric utilities pursuant to subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act. The procurement
process set forth in Section 1-75 of the Illinois Power Agency
Act and subsection (e) of this Section shall be administered
by a procurement administrator and monitored by a procurement
monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section
following Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with

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subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for
review and approval on a confidential basis prior to
the procurement event;
(iii) serve as the interface between the electric
utility and suppliers;
(iv) manage the bidder pre-qualification and
registration process;
(v) obtain the electric utilities' agreement to
the final form of all supply contracts and credit
collateral agreements;
(vi) administer the request for proposals process;
(vii) have the discretion to negotiate to
determine whether bidders are willing to lower the
price of bids that meet the benchmarks approved by the
Commission; any post-bid negotiations with bidders
shall be limited to price only and shall be completed
within 24 hours after opening the sealed bids and
shall be conducted in a fair and unbiased manner; in
conducting the negotiations, there shall be no
disclosure of any information derived from proposals
submitted by competing bidders; if information is
disclosed to any bidder, it shall be provided to all
competing bidders;
(viii) maintain confidentiality of supplier and
bidding information in a manner consistent with all

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applicable laws, rules, regulations, and tariffs;
(ix) submit a confidential report to the
Commission recommending acceptance or rejection of
bids;
(x) notify the utility of contract counterparties
and contract specifics; and
(xi) administer related contingency procurement
events.
(2) The procurement monitor, who shall be retained by
the Commission, shall:
(i) monitor interactions among the procurement
administrator, suppliers, and utility;
(ii) monitor and report to the Commission on the
progress of the procurement process;
(iii) provide an independent confidential report
to the Commission regarding the results of the
procurement event;
(iv) assess compliance with the procurement plans
approved by the Commission for each utility that on
December 31, 2005 provided electric service to at
least 100,000 customers in Illinois and for each small
multi-jurisdictional utility that on December 31, 2005
served less than 100,000 customers in Illinois;
(v) preserve the confidentiality of supplier and
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;

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(vi) provide expert advice to the Commission and
consult with the procurement administrator regarding
issues related to procurement process design, rules,
protocols, and policy-related matters; and
(vii) consult with the procurement administrator
regarding the development and use of benchmark
criteria, standard form contracts, credit policies,
and bid documents.
(d) Except as provided in subsection (j), the planning
process shall be conducted as follows:
(1) Beginning in 2008, each Illinois utility procuring
power pursuant to this Section shall annually provide a
range of load forecasts to the Illinois Power Agency by
July 15 of each year, or such other date as may be required
by the Commission or Agency. The load forecasts shall
cover the 5-year procurement planning period for the next
procurement plan and shall include hourly data
representing a high-load, low-load, and expected-load
scenario for the load of those retail customers included
in the plan's electric supply service requirements. The
utility shall provide supporting data and assumptions for
each of the scenarios.
(2) Beginning in 2008, the Illinois Power Agency shall
prepare a procurement plan by August 15th of each year, or
such other date as may be required by the Commission. The
procurement plan shall identify the portfolio of

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demand-response and power and energy products to be
procured. Cost-effective demand-response measures shall be
procured as set forth in item (iii) of subsection (b) of
this Section. Copies of the procurement plan shall be
posted and made publicly available on the Agency's and
Commission's websites, and copies shall also be provided
to each affected electric utility. An affected utility
shall have 30 days following the date of posting to
provide comment to the Agency on the procurement plan.
Other interested entities also may comment on the
procurement plan. All comments submitted to the Agency
shall be specific, supported by data or other detailed
analyses, and, if objecting to all or a portion of the
procurement plan, accompanied by specific alternative
wording or proposals. All comments shall be posted on the
Agency's and Commission's websites. During this 30-day
comment period, the Agency shall hold at least one public
hearing within each utility's service area for the purpose
of receiving public comment on the procurement plan.
Within 14 days following the end of the 30-day review
period, the Agency shall revise the procurement plan as
necessary based on the comments received and file the
procurement plan with the Commission and post the
procurement plan on the websites.
(3) Within 5 days after the filing of the procurement
plan, any person objecting to the procurement plan shall

HB3758 - 379 - LRB104 12225 JDS 22331 b
file an objection with the Commission. Within 10 days
after the filing, the Commission shall determine whether a
hearing is necessary. The Commission shall enter its order
confirming or modifying the procurement plan within 90
days after the filing of the procurement plan by the
Illinois Power Agency.
(4) The Commission shall approve the procurement plan,
including expressly the forecast used in the procurement
plan, if the Commission determines that it will ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability.
(4.5) The Commission shall review the Agency's
recommendations for the selection of applicants to enter
into long-term contracts for the sale and delivery of
renewable energy credits from new renewable energy
facilities to be constructed at or adjacent to the sites
of coal-fueled electric generating facilities in this
State in accordance with the provisions of subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act,
and shall approve the Agency's recommendations if the
Commission determines that the applicants recommended by
the Agency for selection, the proposed new renewable
energy facilities to be constructed, the amounts of
renewable energy credits to be delivered pursuant to the

HB3758 - 380 - LRB104 12225 JDS 22331 b
contracts, and the other terms of the contracts, are
consistent with the requirements of subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act.
(e) The procurement process shall include each of the
following components:
(1) Solicitation, pre-qualification, and registration
of bidders. The procurement administrator shall
disseminate information to potential bidders to promote a
procurement event, notify potential bidders that the
procurement administrator may enter into a post-bid price
negotiation with bidders that meet the applicable
benchmarks, provide supply requirements, and otherwise
explain the competitive procurement process. In addition
to such other publication as the procurement administrator
determines is appropriate, this information shall be
posted on the Illinois Power Agency's and the Commission's
websites. The procurement administrator shall also
administer the prequalification process, including
evaluation of credit worthiness, compliance with
procurement rules, and agreement to the standard form
contract developed pursuant to paragraph (2) of this
subsection (e). The procurement administrator shall then
identify and register bidders to participate in the
procurement event.
(2) Standard contract forms and credit terms and
instruments. The procurement administrator, in

HB3758 - 381 - LRB104 12225 JDS 22331 b
consultation with the utilities, the Commission, and other
interested parties and subject to Commission oversight,
shall develop and provide standard contract forms for the
supplier contracts that meet generally accepted industry
practices. Standard credit terms and instruments that meet
generally accepted industry practices shall be similarly
developed. The procurement administrator shall make
available to the Commission all written comments it
receives on the contract forms, credit terms, or
instruments. If the procurement administrator cannot reach
agreement with the applicable electric utility as to the
contract terms and conditions, the procurement
administrator must notify the Commission of any disputed
terms and the Commission shall resolve the dispute. Except
as provided under item (vi) of subparagraph (G) of
paragraph (1) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act, the The terms of the contracts
shall not be subject to negotiation by winning bidders,
and the bidders must agree to the terms of the contract in
advance so that winning bids are selected solely on the
basis of price.
(3) Establishment of a market-based price benchmark.
As part of the development of the procurement process, the
procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor, shall establish benchmarks for evaluating the

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final prices in the contracts for each of the products
that will be procured through the procurement process. The
benchmarks shall be based on price data for similar
products for the same delivery period and same delivery
hub, or other delivery hubs after adjusting for that
difference. The price benchmarks may also be adjusted to
take into account differences between the information
reflected in the underlying data sources and the specific
products and procurement process being used to procure
power for the Illinois utilities. The benchmarks shall be
confidential but shall be provided to, and will be subject
to Commission review and approval, prior to a procurement
event.
(4) Request for proposals competitive procurement
process. The procurement administrator shall design and
issue a request for proposals to supply electricity in
accordance with each utility's procurement plan, as
approved by the Commission. The request for proposals
shall set forth a procedure for sealed, binding commitment
bidding with pay-as-bid settlement, and provision for
selection of bids on the basis of price.
(5) A plan for implementing contingencies in the event
of supplier default or failure of the procurement process
to fully meet the expected load requirement due to
insufficient supplier participation, Commission rejection
of results, or any other cause.

HB3758 - 383 - LRB104 12225 JDS 22331 b
(i) Event of supplier default: In the event of
supplier default, the utility shall review the
contract of the defaulting supplier to determine if
the amount of supply is 200 megawatts or greater, and
if there are more than 60 days remaining of the
contract term. If both of these conditions are met,
and the default results in termination of the
contract, the utility shall immediately notify the
Illinois Power Agency that a request for proposals
must be issued to procure replacement power, and the
procurement administrator shall run an additional
procurement event. If the contracted supply of the
defaulting supplier is less than 200 megawatts or
there are less than 60 days remaining of the contract
term, the utility shall procure power and energy from
the applicable regional transmission organization
market, including ancillary services, capacity, and
day-ahead or real time energy, or both, for the
duration of the contract term to replace the
contracted supply; provided, however, that if a needed
product is not available through the regional
transmission organization market it shall be purchased
from the wholesale market.
(ii) Failure of the procurement process to fully
meet the expected load requirement: If the procurement
process fails to fully meet the expected load

HB3758 - 384 - LRB104 12225 JDS 22331 b
requirement due to insufficient supplier participation
or due to a Commission rejection of the procurement
results, the procurement administrator, the
procurement monitor, and the Commission staff shall
meet within 10 days to analyze potential causes of low
supplier interest or causes for the Commission
decision. If changes are identified that would likely
result in increased supplier participation, or that
would address concerns causing the Commission to
reject the results of the prior procurement event, the
procurement administrator may implement those changes
and rerun the request for proposals process according
to a schedule determined by those parties and
consistent with Section 1-75 of the Illinois Power
Agency Act and this subsection. In any event, a new
request for proposals process shall be implemented by
the procurement administrator within 90 days after the
determination that the procurement process has failed
to fully meet the expected load requirement.
(iii) In all cases where there is insufficient
supply provided under contracts awarded through the
procurement process to fully meet the electric
utility's load requirement, the utility shall meet the
load requirement by procuring power and energy from
the applicable regional transmission organization
market, including ancillary services, capacity, and

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day-ahead or real time energy, or both; provided,
however, that if a needed product is not available
through the regional transmission organization market
it shall be purchased from the wholesale market.
(6) The procurement processes described in this
subsection, in Section 1-93 of the Illinois Power Agency
Act, and in subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act are exempt from the requirements
of the Illinois Procurement Code, pursuant to Section
20-10 of that Code.
(f) Within 2 business days after opening the sealed bids,
the procurement administrator shall submit a confidential
report to the Commission. The report shall contain the results
of the bidding for each of the products along with the
procurement administrator's recommendation for the acceptance
and rejection of bids based on the price benchmark criteria
and other factors observed in the process. The procurement
monitor also shall submit a confidential report to the
Commission within 2 business days after opening the sealed
bids. The report shall contain the procurement monitor's
assessment of bidder behavior in the process as well as an
assessment of the procurement administrator's compliance with
the procurement process and rules. The Commission shall review
the confidential reports submitted by the procurement
administrator and procurement monitor, and shall accept or
reject the recommendations of the procurement administrator

HB3758 - 386 - LRB104 12225 JDS 22331 b
within 2 business days after receipt of the reports.
(g) Within 3 business days after the Commission decision
approving the results of a procurement event, the utility
shall enter into binding contractual arrangements with the
winning suppliers using the standard form contracts; except
that the utility shall not be required either directly or
indirectly to execute the contracts if a tariff that is
consistent with subsection (l) of this Section has not been
approved and placed into effect for that utility.
(h) For the procurement of standard wholesale products,
the names of the successful bidders and the load weighted
average of the winning bid prices for each contract type and
for each contract term shall be made available to the public at
the time of Commission approval of a procurement event. For
procurements conducted to meet the requirements of subsection
(b) of Section 1-56 or subsection (c) of Section 1-75 of the
Illinois Power Agency Act governed by the provisions of this
Section, the address and nameplate capacity of the new
renewable energy generating facility proposed by a winning
bidder shall also be made available to the public at the time
of Commission approval of a procurement event, along with the
business address and contact information for any winning
bidder. An estimate or approximation of the nameplate capacity
of the new renewable energy generating facility may be
disclosed if necessary to protect the confidentiality of
individual bid prices.

HB3758 - 387 - LRB104 12225 JDS 22331 b
The Commission, the procurement monitor, the procurement
administrator, the Illinois Power Agency, and all participants
in the procurement process shall maintain the confidentiality
of all other supplier and bidding information in a manner
consistent with all applicable laws, rules, regulations, and
tariffs. Confidential information, including the confidential
reports submitted by the procurement administrator and
procurement monitor pursuant to subsection (f) of this
Section, shall not be made publicly available and shall not be
discoverable by any party in any proceeding, absent a
compelling demonstration of need, nor shall those reports be
admissible in any proceeding other than one for law
enforcement purposes.
(h-5) For procurements conducted to meet the requirements
of subsection (b) of Section 1-56 or subsection (c) of Section
1-75 of the Illinois Power Agency Act, the Illinois Power
Agency shall release aggregated information related to
participation levels across product types and the basis of
rejection for non-accepted bids if the Commission, the
procurement monitor, the procurement administrator, and the
Illinois Power Agency determine that the release of this
information would not result in the disclosure of confidential
bid information or negatively impact the competitiveness of
future renewable energy credit procurements.
(i) Within 2 business days after a Commission decision
approving the results of a procurement event or such other

HB3758 - 388 - LRB104 12225 JDS 22331 b
date as may be required by the Commission from time to time,
the utility shall file for informational purposes with the
Commission its actual or estimated retail supply charges, as
applicable, by customer supply group reflecting the costs
associated with the procurement and computed in accordance
with the tariffs filed pursuant to subsection (l) of this
Section and approved by the Commission.
(j) Within 60 days following August 28, 2007 (the
effective date of Public Act 95-481), each electric utility
that on December 31, 2005 provided electric service to at
least 100,000 customers in Illinois shall prepare and file
with the Commission an initial procurement plan, which shall
conform in all material respects to the requirements of the
procurement plan set forth in subsection (b); provided,
however, that the Illinois Power Agency Act shall not apply to
the initial procurement plan prepared pursuant to this
subsection. The initial procurement plan shall identify the
portfolio of power and energy products to be procured and
delivered for the period June 2008 through May 2009, and shall
identify the proposed procurement administrator, who shall
have the same experience and expertise as is required of a
procurement administrator hired pursuant to Section 1-75 of
the Illinois Power Agency Act. Copies of the procurement plan
shall be posted and made publicly available on the
Commission's website. The initial procurement plan may include
contracts for renewable resources that extend beyond May 2009.

HB3758 - 389 - LRB104 12225 JDS 22331 b
(i) Within 14 days following filing of the initial
procurement plan, any person may file a detailed objection
with the Commission contesting the procurement plan
submitted by the electric utility. All objections to the
electric utility's plan shall be specific, supported by
data or other detailed analyses. The electric utility may
file a response to any objections to its procurement plan
within 7 days after the date objections are due to be
filed. Within 7 days after the date the utility's response
is due, the Commission shall determine whether a hearing
is necessary. If it determines that a hearing is
necessary, it shall require the hearing to be completed
and issue an order on the procurement plan within 60 days
after the filing of the procurement plan by the electric
utility.
(ii) The order shall approve or modify the procurement
plan, approve an independent procurement administrator,
and approve or modify the electric utility's tariffs that
are proposed with the initial procurement plan. The
Commission shall approve the procurement plan if the
Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability.
(k) (Blank).
(k-5) (Blank).

HB3758 - 390 - LRB104 12225 JDS 22331 b
(l) An electric utility shall recover its costs incurred
under this Section and subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act, including, but not limited to, the
costs of procuring power and energy demand-response resources
under this Section and its costs for purchasing renewable
energy credits pursuant to subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act. The utility shall file with the
initial procurement plan its proposed tariffs through which
its costs of procuring power that are incurred pursuant to a
Commission-approved procurement plan and those other costs
identified in this subsection (l), will be recovered. The
tariffs shall include a formula rate or charge designed to
pass through both the costs incurred by the utility in
procuring a supply of electric power and energy for the
applicable customer classes with no mark-up or return on the
price paid by the utility for that supply, plus any just and
reasonable costs that the utility incurs in arranging and
providing for the supply of electric power and energy. The
formula rate or charge shall also contain provisions that
ensure that its application does not result in over or under
recovery due to changes in customer usage and demand patterns,
and that provide for the correction, on at least an annual
basis, of any accounting errors that may occur. A utility
shall recover through the tariff all reasonable costs incurred
to implement or comply with any procurement plan that is
developed and put into effect pursuant to Section 1-75 of the

HB3758 - 391 - LRB104 12225 JDS 22331 b
Illinois Power Agency Act and this Section, and for the
procurement of renewable energy credits pursuant to subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act,
including any fees assessed by the Illinois Power Agency,
costs associated with load balancing, and contingency plan
costs. The electric utility shall also recover its full costs
of procuring electric supply for which it contracted before
the effective date of this Section in conjunction with the
provision of full requirements service under fixed-price
bundled service tariffs subsequent to December 31, 2006. All
such costs shall be deemed to have been prudently incurred.
The pass-through tariffs that are filed and approved pursuant
to this Section shall not be subject to review under, or in any
way limited by, Section 16-111(i) of this Act. All of the costs
incurred by the electric utility associated with the purchase
of zero emission credits in accordance with subsection (d-5)
of Section 1-75 of the Illinois Power Agency Act, all costs
incurred by the electric utility associated with the purchase
of carbon mitigation credits in accordance with subsection
(d-10) of Section 1-75 of the Illinois Power Agency Act, and,
beginning June 1, 2017, all of the costs incurred by the
electric utility associated with the purchase of renewable
energy resources in accordance with Sections 1-56 and 1-75 of
the Illinois Power Agency Act, and all of the costs incurred by
the electric utility in purchasing renewable energy credits in
accordance with subsection (c-5) of Section 1-75 of the

HB3758 - 392 - LRB104 12225 JDS 22331 b
Illinois Power Agency Act, and all costs incurred by the
electric utility in purchasing energy storage resources, net
of any revenues to the electric utility, in accordance with
Section 1-93 of the Illinois Power Agency Act shall be
recovered through the electric utility's tariffed charges
applicable to all of its retail customers, as specified in
subsection (k) or subsection (i-5), as applicable, of Section
16-108 of this Act, and shall not be recovered through the
electric utility's tariffed charges for electric power and
energy supply to its eligible retail customers.
(m) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following August 28,
2007 (the effective date of Public Act 95-481).
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single procurement
plan covering their combined needs may procure for those
combined needs in conjunction with that plan, and may enter
jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to
their requirements.
(o) On or before June 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments

HB3758 - 393 - LRB104 12225 JDS 22331 b
on the prior year's procurement process and any
recommendations for change.
(p) An electric utility subject to this Section may
propose to invest, lease, own, or operate an electric
generation facility as part of its procurement plan, provided
the utility demonstrates that such facility is the least-cost
option to provide electric service to those retail customers
included in the plan's electric supply service requirements.
If the facility is shown to be the least-cost option and is
included in a procurement plan prepared in accordance with
Section 1-75 of the Illinois Power Agency Act and this
Section, then the electric utility shall make a filing
pursuant to Section 8-406 of this Act, and may request of the
Commission any statutory relief required thereunder. If the
Commission grants all of the necessary approvals for the
proposed facility, such supply shall thereafter be considered
as a pre-existing contract under subsection (b) of this
Section. The Commission shall in any order approving a
proposal under this subsection specify how the utility will
recover the prudently incurred costs of investing in, leasing,
owning, or operating such generation facility through just and
reasonable rates charged to those retail customers included in
the plan's electric supply service requirements. Cost recovery
for facilities included in the utility's procurement plan
pursuant to this subsection shall not be subject to review
under or in any way limited by the provisions of Section

HB3758 - 394 - LRB104 12225 JDS 22331 b
16-111(i) of this Act. Nothing in this Section is intended to
prohibit a utility from filing for a fuel adjustment clause as
is otherwise permitted under Section 9-220 of this Act.
(q) If the Illinois Power Agency filed with the
Commission, under Section 16-111.5 of this Act, its proposed
procurement plan for the period commencing June 1, 2017, and
the Commission has not yet entered its final order approving
the plan on or before the effective date of this amendatory Act
of the 99th General Assembly, then the Illinois Power Agency
shall file a notice of withdrawal with the Commission, after
the effective date of this amendatory Act of the 99th General
Assembly, to withdraw the proposed procurement of renewable
energy resources to be approved under the plan, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices using funds previously
collected from electric utilities' retail customers that take
service pursuant to electric utilities' hourly pricing tariff
or tariffs and, for an electric utility that serves less than
100,000 retail customers in the State, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices. Upon receipt of the
notice, the Commission shall enter an order that approves the
withdrawal of the proposed procurement of renewable energy
resources from the plan. The initially proposed procurement of
renewable energy resources shall not be approved or be the
subject of any further hearing, investigation, proceeding, or

HB3758 - 395 - LRB104 12225 JDS 22331 b
order of any kind.
This amendatory Act of the 99th General Assembly preempts
and supersedes any order entered by the Commission that
approved the Illinois Power Agency's procurement plan for the
period commencing June 1, 2017, to the extent it is
inconsistent with the provisions of this amendatory Act of the
99th General Assembly. To the extent any previously entered
order approved the procurement of renewable energy resources,
the portion of that order approving the procurement shall be
void, other than the procurement of renewable energy credits
from distributed renewable energy generation devices using
funds previously collected from electric utilities' retail
customers that take service under electric utilities' hourly
pricing tariff or tariffs and, for an electric utility that
serves less than 100,000 retail customers in the State, other
than the procurement of renewable energy credits for
distributed renewable energy generation devices.
(Source: P.A. 102-662, eff. 9-15-21.)
(220 ILCS 5/16-115)
Sec. 16-115. Certification of alternative retail electric
suppliers.
(a) Any alternative retail electric supplier must obtain a
certificate of service authority from the Commission in
accordance with this Section before serving any retail
customer or other user located in this State. An alternative

HB3758 - 396 - LRB104 12225 JDS 22331 b
retail electric supplier may request, and the Commission may
grant, a certificate of service authority for the entire State
or for a specified geographic area of the State. A certificate
granted pursuant to this Section is not property, and the
grant of a certificate to an entity does not create a property
interest in the certificate. This Section does not diminish
the existing rights of a certificate holder to notice and
hearing as proscribed by the Illinois Administrative Procedure
Act and in rules adopted by the Commission.
(b) An alternative retail electric supplier seeking a
certificate of service authority shall file with the
Commission a verified application containing information
showing that the applicant meets the requirements of this
Section. The alternative retail electric supplier shall
publish notice of its application in the official State
newspaper within 10 days following the date of its filing. No
later than 45 days after a complete application is properly
filed with the Commission, and such notice is published, the
Commission shall issue its order granting or denying the
application.
(c) An application for a certificate of service authority
shall identify the area or areas in which the applicant
intends to offer service and the types of services it intends
to offer. Applicants that seek to serve residential or small
commercial retail customers within a geographic area that is
smaller than an electric utility's service area shall submit

HB3758 - 397 - LRB104 12225 JDS 22331 b
evidence demonstrating that the designation of this smaller
area does not violate Section 16-115A. An applicant that seeks
to serve residential or small commercial retail customers may
state in its application for certification any limitations
that will be imposed on the number of customers or maximum load
to be served.
(d) The Commission shall grant the application for a
certificate of service authority if it makes the findings set
forth in this subsection based on the verified application and
such other information as the applicant may submit:
(1) That the applicant possesses sufficient technical,
financial, and managerial resources and abilities to
provide the service for which it seeks a certificate of
service authority. In determining the level of technical,
financial, and managerial resources and abilities which
the applicant must demonstrate, the Commission shall
consider (i) the characteristics, including the size and
financial sophistication, of the customers that the
applicant seeks to serve, and (ii) whether the applicant
seeks to provide electric power and energy using property,
plant, and equipment which it owns, controls, or operates;
(2) That the applicant will comply with all applicable
federal, State, regional, and industry rules, policies,
practices, and procedures for the use, operation, and
maintenance of the safety, integrity, and reliability, of
the interconnected electric transmission system;

HB3758 - 398 - LRB104 12225 JDS 22331 b
(3) That the applicant will only provide service to
retail customers in an electric utility's service area
that are eligible to take delivery services under this
Act;
(4) That the applicant will comply with such
informational or reporting requirements as the Commission
may by rule establish and provide the information required
by Section 16-112. Any data related to contracts for the
purchase and sale of electric power and energy shall be
made available for review by the Staff of the Commission
on a confidential and proprietary basis and only to the
extent and for the purposes which the Commission
determines are reasonably necessary in order to carry out
the purposes of this Act;
(5) That the applicant will procure renewable energy
resources in accordance with Section 16-115D of this Act,
and will source electricity from clean coal facilities, as
defined in Section 1-10 of the Illinois Power Agency Act,
in amounts at least equal to the percentages set forth in
subsections (c) and (d) of Section 1-75 of the Illinois
Power Agency Act. For purposes of this Section:
(i) (blank);
(ii) (blank);
(iii) the required sourcing of electricity
generated by clean coal facilities, other than the
initial clean coal facility, shall be limited to the

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amount of electricity that can be procured or sourced
at a price at or below the benchmarks approved by the
Commission each year in accordance with item (1) of
subsection (c) and items (1) and (5) of subsection (d)
of Section 1-75 of the Illinois Power Agency Act;
(iv) all alternative retail electric suppliers
shall execute a sourcing agreement to source
electricity from the initial clean coal facility, on
the terms set forth in paragraphs (3) and (4) of
subsection (d) of Section 1-75 of the Illinois Power
Agency Act, except that in lieu of the requirements in
subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of
paragraph (3) of that subsection (d), the applicant
shall execute one or more of the following:
(1) if the sourcing agreement is a power
purchase agreement, a contract with the initial
clean coal facility to purchase in each hour an
amount of electricity equal to all clean coal
energy made available from the initial clean coal
facility during such hour, which the utilities are
not required to procure under the terms of
subsection (d) of Section 1-75 of the Illinois
Power Agency Act, multiplied by a fraction, the
numerator of which is the alternative retail
electric supplier's retail market sales of
electricity (expressed in kilowatthours sold) in

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the State during the prior calendar month and the
denominator of which is the total sales of
electricity (expressed in kilowatthours sold) in
the State by alternative retail electric suppliers
during such prior month that are subject to the
requirements of this paragraph (5) of subsection
(d) of this Section and subsection (d) of Section
1-75 of the Illinois Power Agency Act plus the
total sales of electricity (expressed in
kilowatthours sold) by utilities outside of their
service areas during such prior month, pursuant to
subsection (c) of Section 16-116 of this Act; or
(2) if the sourcing agreement is a contract
for differences, a contract with the initial clean
coal facility in each hour with respect to an
amount of electricity equal to all clean coal
energy made available from the initial clean coal
facility during such hour, which the utilities are
not required to procure under the terms of
subsection (d) of Section 1-75 of the Illinois
Power Agency Act, multiplied by a fraction, the
numerator of which is the alternative retail
electric supplier's retail market sales of
electricity (expressed in kilowatthours sold) in
the State during the prior calendar month and the
denominator of which is the total sales of

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electricity (expressed in kilowatthours sold) in
the State by alternative retail electric suppliers
during such prior month that are subject to the
requirements of this paragraph (5) of subsection
(d) of this Section and subsection (d) of Section
1-75 of the Illinois Power Agency Act plus the
total sales of electricity (expressed in
kilowatthours sold) by utilities outside of their
service areas during such prior month, pursuant to
subsection (c) of Section 16-116 of this Act;
(v) if, in any year after the first year of
commercial operation, the owner of the clean coal
facility fails to demonstrate to the Commission that
the initial clean coal facility captured and
sequestered at least 50% of the total carbon emissions
that the facility would otherwise emit or that
sequestration of emissions from prior years has
failed, resulting in the release of carbon into the
atmosphere, the owner of the facility must offset
excess emissions. Any such carbon offsets must be
permanent, additional, verifiable, real, located
within the State of Illinois, and legally and
practicably enforceable. The costs of any such offsets
that are not recoverable shall not exceed $15,000,000
in any given year. No costs of any such purchases of
carbon offsets may be recovered from an alternative

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retail electric supplier or its customers. All carbon
offsets purchased for this purpose and any carbon
emission credits associated with sequestration of
carbon from the facility must be permanently retired.
The initial clean coal facility shall not forfeit its
designation as a clean coal facility if the facility
fails to fully comply with the applicable carbon
sequestration requirements in any given year, provided
the requisite offsets are purchased. However, the
Attorney General, on behalf of the People of the State
of Illinois, may specifically enforce the facility's
sequestration requirement and the other terms of this
contract provision. Compliance with the sequestration
requirements and offset purchase requirements that
apply to the initial clean coal facility shall be
reviewed annually by an independent expert retained by
the owner of the initial clean coal facility, with the
advance written approval of the Attorney General;
(vi) The Commission shall, after notice and
hearing, revoke the certification of any alternative
retail electric supplier that fails to execute a
sourcing agreement with the initial clean coal
facility as required by item (5) of subsection (d) of
this Section. The sourcing agreements with this
initial clean coal facility shall be subject to both
approval of the initial clean coal facility by the

HB3758 - 403 - LRB104 12225 JDS 22331 b
General Assembly and satisfaction of the requirements
of item (4) of subsection (d) of Section 1-75 of the
Illinois Power Agency Act, and shall be executed
within 90 days after any such approval by the General
Assembly. The Commission shall not accept an
application for certification from an alternative
retail electric supplier that has lost certification
under this subsection (d), or any corporate affiliate
thereof, for at least one year from the date of
revocation;
(6) With respect to an applicant that seeks to serve
residential or small commercial retail customers, that the
area to be served by the applicant and any limitations it
proposes on the number of customers or maximum amount of
load to be served meet the provisions of Section 16-115A,
provided, that the Commission can extend the time for
considering such a certificate request by up to 90 days,
and can schedule hearings on such a request;
(7) That the applicant meets the requirements of
subsection (a) of Section 16-128;
(8) That the applicant discloses whether the applicant
is the subject of any lawsuit filed in a court of law or
formal complaint filed with a regulatory agency alleging
fraud, deception, or unfair marketing practices or other
similar allegations and, if the applicant is the subject
of such lawsuit or formal complaint, the applicant shall

HB3758 - 404 - LRB104 12225 JDS 22331 b
identify the name, case number, and jurisdiction of each
lawsuit or complaint, and that the applicant is capable of
fulfilling its obligations as an alternative retail
electric supplier in Illinois notwithstanding any lawsuit
or complaint. For the purpose of this item (8), "formal
complaint" includes only those complaints that seek a
binding determination from a State or federal regulatory
body;
(9) That the applicant shall at all times remain in
compliance with requirements for certification stated in
this Section and as the Commission may establish by rule;
(10) That the applicant shall execute and maintain a
license or permit bond issued by a qualifying surety or
insurance company authorized to transact business in the
State of Illinois in favor of the People of the State of
Illinois. The amount of the bond shall equal $30,000 if
the applicant seeks to serve only nonresidential retail
customers with maximum electrical demands of one megawatt
or more, $150,000 if the applicant seeks to serve only
nonresidential retail customers with annual electrical
consumption greater than 15,000 kilowatt-hours, or
$500,000 if the applicant seeks to serve all eligible
customers. Applicants shall be required to submit an
additional $500,000 bond if the applicant intends to
market to residential customers using in-person
solicitations. The bonds shall be conditioned upon the

HB3758 - 405 - LRB104 12225 JDS 22331 b
full and faithful performance of all duties and
obligations of the applicant as an alternative retail
electric supplier, shall be valid for a period of not less
than one year, and may be drawn upon in whole or in part to
satisfy any penalties imposed, and finally adjudicated, by
the Commission pursuant to Section 16-115B for a violation
of the applicant's duties or obligations, except that the
total amount of claims and penalties against the bond
shall not exceed the penal sum of the bond and shall not
include any consequential or punitive damage. The cost of
the bond shall be paid by the applicant. The applicant
shall file a copy of this bond, with a notarized
verification page from the issuer, as part of its
application for certification under 83 Ill. Adm. Code 451;
and
(11) That the applicant will comply with all other
applicable laws and regulations.
(d-3) The Commission may deny with prejudice an
application in which the applicant fails to provide the
Commission with information sufficient for the Commission to
grant the application.
(d-5) (Blank).
(d-10) Transmission co-location customer. Within 120 days
of the effective date of this Amendatory Act of the 104th
General Assembly, the Commission shall initiate a rulemaking
applicable to the certification and annual recertification of

HB3758 - 406 - LRB104 12225 JDS 22331 b
co-location customers as an alternative retail electric
supplier. The rulemaking shall include minimum standards for
the contractual relationship between the generator(s), the
energy storage, and the load to the extent that such entities
are not owned by a common parent or otherwise affiliated. An
alternative retail electric supplier that is a transmission
co-location customer may not serve any retail customer and
must serve only the transmission co-location customer.
(d-15) Distribution co-location customer. Within 120 days
of the effective date of this Amendatory Act of the 104th
General Assembly, the Commission shall initiate a rulemaking
applicable to the certification and annual recertification of
co-location customers as an alternative retail electric
supplier. The rulemaking shall include minimum standards for
the contractual relationship between the generator(s), the
energy storage, and the load(s) to the extent that such
entities are not owned by a common parent or otherwise
affiliated. An alternative retail electric supplier that is a
distribution co-location customer may not serve any retail
customer and must serve only the distribution co-location
customer.
(e) A retail customer that owns a cogeneration or
self-generation facility and that seeks certification only to
provide electric power and energy from such facility to retail
customers at separate locations which customers are both (i)
owned by, or a subsidiary or other corporate affiliate of,

HB3758 - 407 - LRB104 12225 JDS 22331 b
such applicant and (ii) eligible for delivery services, shall
be granted a certificate of service authority upon filing an
application and notifying the Commission that it has entered
into an agreement with the relevant electric utilities
pursuant to Section 16-118. Provided, however, that if the
retail customer owning such cogeneration or self-generation
facility would not be charged a transition charge due to the
exemption provided under subsection (f) of Section 16-108
prior to the certification, and the retail customers at
separate locations are taking delivery services in conjunction
with purchasing power and energy from the facility, the retail
customer on whose premises the facility is located shall not
thereafter be required to pay transition charges on the power
and energy that such retail customer takes from the facility.
(f) The Commission shall have the authority to promulgate
rules and regulations to carry out the provisions of this
Section. On or before May 1, 1999, the Commission shall adopt a
rule or rules applicable to the certification of those
alternative retail electric suppliers that seek to serve only
nonresidential retail customers with maximum electrical
demands of one megawatt or more which shall provide for (i)
expedited and streamlined procedures for certification of such
alternative retail electric suppliers and (ii) specific
criteria which, if met by any such alternative retail electric
supplier, shall constitute the demonstration of technical,
financial and managerial resources and abilities to provide

HB3758 - 408 - LRB104 12225 JDS 22331 b
service required by paragraph (1) of subsection (d) of this
Section, such as a requirement to post a bond or letter of
credit, from a responsible surety or financial institution, of
sufficient size for the nature and scope of the services to be
provided; demonstration of adequate insurance for the scope
and nature of the services to be provided; and experience in
providing similar services in other jurisdictions.
(g) An alternative retail electric supplier may seek
confidential treatment for the following information by filing
an affidavit with the Commission so long as the affidavit
meets the requirements in this subsection (g):
(1) the total annual kilowatt-hours delivered and sold
by an alternative retail electric supplier to retail
customers within each utility service territory and the
total annual kilowatt-hours delivered and sold by an
alternative retail electric supplier to retail customers
in all utility service territories in the preceding
calendar year as required by 83 Ill. Adm. Code 451.770;
(2) the total peak demand supplied by an alternative
retail electric supplier during the previous year in each
utility service territory as required by 83 Ill. Adm. Code
465.40;
(3) a good faith estimate of the amount an alternative
retail electric supplier expects to be obliged to pay the
utility under single billing tariffs during the next 12
months and the amount of any bond or letter of credit used

HB3758 - 409 - LRB104 12225 JDS 22331 b
to demonstrate an alternative retail electric supplier's
credit worthiness to provide single billing services
pursuant to 83 Ill. Adm. Code 451.510(a) and (b).
The affidavit must be filed contemporaneously with the
information for which confidential treatment is sought and
must clearly state that the affiant seeks confidential
treatment pursuant to this subsection (g) and the information
for which confidential treatment is sought must be clearly
identified on the confidential version of the document filed
with the Commission. The affidavit must be accompanied by a
"confidential" and a "public" version of the document or
documents containing the information for which confidential
treatment is sought.
If the alternative retail electric supplier has met the
affidavit requirements of this subsection (g), then the
Commission shall afford confidential treatment to the
information identified in the affidavit for a period of 2
years after the date the affidavit is received by the
Commission.
Nothing in this subsection (g) prevents an alternative
retail electric supplier from filing a petition with the
Commission seeking confidential treatment for information
beyond that identified in this subsection (g) or for
information contained in other reports or documents filed with
the Commission other than annual rate reports.
Nothing in this subsection (g) prevents the Commission, on

HB3758 - 410 - LRB104 12225 JDS 22331 b
its own motion, or any party from filing a formal petition with
the Commission seeking to reconsider the conferring of
confidential status on an item of information afforded
confidential treatment pursuant to this subsection (g).
The Commission, on its own motion, may at any time
initiate a docketed proceeding to investigate the continued
applicability of this subsection (g) to the information
contained in items (i), (ii), and (iii) of this subsection
(g). If, at the end of such investigation, the Commission
determines that a particular item of information should no
longer be eligible for the affidavit-based process outlined in
this subsection (g), the Commission may enter an order to
remove that item from the list of items eligible for the
process set forth in this subsection (g). Notwithstanding any
such order, in the event the Commission makes such a
determination, nothing in this subsection (g) prevents an
alternative retail electric supplier desiring confidential
treatment for such information from filing a formal petition
with the Commission seeking confidential treatment for such
information.
(Source: P.A. 101-590, eff. 1-1-20; 102-958, eff. 1-1-23.)
(220 ILCS 5/16-136 new)
Sec. 16-136. Co-Location Customers.
(a) It is the policy of the State to attract and encourage
investment in large-scale infrastructure while fostering a

HB3758 - 411 - LRB104 12225 JDS 22331 b
transition to renewable generation and storage. It is further
the policy of the State to encourage new development by
minimizing project delays while ensuring that each public
utility can operate its system in a safe, reliable manner.
(b) Transmission co-location customers.
(1) Each electric utility serving at least 50,000
customers as of January 1, 2024 shall not require a
transmission co-location customer to interconnect with
such electric utility's distribution system. Each such
electric utility shall not take any action to prevent a
transmission co-location customer from interconnecting to
such electric utility's transmission system or the
transmission assets of a third party.
(2) Notwithstanding anything to the contrary, no
electric utility shall have an obligation to provide
delivery service to a transmission co-location customer.
(3) The electrical connections between the end-use
customer of power and energy and the generator(s) and as
applicable the energy storage system(s) shall be owned and
operated by the transmission co-location customer. The
electric utility shall not meter or require the
interconnection customer or a third party to meter or
provide metering information related to power and energy
flow on the electric connections between the end-use
customer of power and energy and the generator(s) and as
applicable the energy storage system(s). However, nothing

HB3758 - 412 - LRB104 12225 JDS 22331 b
in this subsection shall be construed to prevent metering
of the imports and exports of the transmission co-location
customer.
(c) Distribution co-location customers.
(1) Within 120 days of the effective date of this
amendatory Act, the Commission shall initiate a rulemaking
regarding interconnection of distribution co-location
customers. At minimum, such rulemaking shall include:
(A) A process for studying the distribution
co-location customer as a single unit rather the load
and generation or storage individually or in any
combination other than all together and a requirement
that no electric utility may refuse interconnection of
a distribution co-location customer that the electric
utility determines may be safely interconnected to the
electric utility's distribution system;
(B) A requirement that the electric utility
provide a single meter measuring the aggregate power
and energy import or export of the distribution
co-location customer and a prohibition on the electric
utility metering or causing a third party to meter
power and energy flow on the electric connections
between the end-use customer of power and energy and
the generator(s) and as applicable the energy storage
system(s); and
(C) A standard interconnection agreement with

HB3758 - 413 - LRB104 12225 JDS 22331 b
commercially reasonable and financeable terms and
conditions.
(2) The electrical connections between the end-use
customer of power and energy and the generator(s) and as
applicable the energy storage system(s) shall be owned and
operated by the distribution co-location customer.
(3) The electric utility shall not prevent any or all
of the generators or storage that comprises a co-location
customer from participating in wholesale markets to the
extent such generator(s) or storage qualifies under the
applicable requirements of PJM Interconnection, LLC or
Midcontinent ISO, Inc.
(4) All billing determinants assessed or measured by
the electric utility shall be based exclusively on the
import and export of the distribution co-location customer
taken as a whole;
(d) Each transmission co-location customer and
distribution co-location customer shall, not later than April
30 of each year, provide in a form prescribed by the Commission
information about the renewable resources (including renewable
energy credits) used to provide power and energy or associated
with power and energy consumed by the load portion of the
transmission co-location customer or distribution co-location
customer.
(220 ILCS 5/Art. XXIII heading new)

HB3758 - 414 - LRB104 12225 JDS 22331 b
ARTICLE XXIII. OFFICE OF INTERCONNECTION AND RENEWABLE
DEVELOPMENT
(220 ILCS 5/23-101 new)
Sec. 23-101. Findings and intent. The General Assembly
finds and declares:
(1) The ability of the Commission and the Illinois
Power Agency to ensure long-term benefits from community
renewable generation projects and distributed renewable
energy generation devices is limited. For Illinois
consumers to continue to receive the substantial financial
and environmental benefits of deployment of distributed
renewable generation resources, including devices paired
with energy storage, the Commission must gather additional
data and proactively identify barriers.
(2) To date, as a result of the Future Energy Jobs Act
and the Climate and Equitable Jobs Act, tens of thousands
of Illinois retail customers of all sizes have experienced
the benefits of new renewable generation.
(3) However, as renewable generation deployment
increases, but remains short of the goals set by the
Climate and Equitable Jobs Act, it is critical that the
Commission proactively identify and address barriers to
achieving those goals.
(4) The Commission should promote the efficient
deployment of distributed renewable generation resources.

HB3758 - 415 - LRB104 12225 JDS 22331 b
(220 ILCS 5/23-105 new)
Sec. 23-105. Definitions. In this Article:
"Director" means the Director of the Office of
Interconnection and Renewable Development.
"Distributed renewable energy resources" means a community
renewable generation device or a distributed renewable energy
generation device as those terms are defined in Section 1-10
of the Illinois Power Agency Act. "Distributed renewable
energy resource" includes storage paired with a community
renewable generation device or a distributed renewable energy
generation device.
"Energy storage system" has the meaning given to that term
in Section 1-10 of the Illinois Power Agency Act.
"Office" means the Office of Interconnection and Renewable
Development.
"Utility-scale solar project" and "utility-scale wind
project" have the meanings given to those terms in Section
1-10 of the Illinois Power Agency Act.
(220 ILCS 5/23-110 new)
Sec. 23-110. Office of Interconnection and Renewable
Development.
(a) Within 90 days after the effective date of this
amendatory Act of the 104th General Assembly, subject to
appropriation, the Commission shall establish an Office of

HB3758 - 416 - LRB104 12225 JDS 22331 b
Interconnection and Renewable Development and employ a
Director of Interconnection and Renewable Development to
oversee the Office. The Director shall have authority to
employ or otherwise retain at least 3 professionals dedicated
to the task of actively seeking out ways to identify barriers
to deployment of distributed renewable energy resources.
(b) The Office shall 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. The Office shall take these steps for
interconnections involving distributed renewable energy
resources, energy storage systems, utility-scale wind
projects, and utility-scale solar projects, including
interconnections to a distribution system or a transmission
system.
(c) The Office shall monitor interconnection between
electric utilities and applicants for interconnection and
interconnection customers. The Office shall request, and
electric utilities shall promptly provide, information and
records related to pending, successful, and terminated
interconnections. The Office shall include at least one
employee with a background in engineering of distribution
interconnections. The Office shall take these steps for
interconnections involving distributed renewable energy
resources, energy storage systems, utility-scale wind

HB3758 - 417 - LRB104 12225 JDS 22331 b
projects, and utility-scale solar projects, including
interconnections to a distribution system or a transmission
system.
(d) The Office shall employ an Ombudsperson who, in
addition to the roles described in paragraph (2) of subsection
(h-5) of Section 16-107.5, is responsible for oversight of all
utility's compliance with the rules adopted under subsection
(h) of Section 16-107.5 and any utility interconnection
policies or procedures. The Ombudsperson may request, and each
electric utility shall timely provide, records and information
as the Ombudsperson may request from time to time to carry out
his or her duties under this subsection or subsection (m) of
Section 1-93 of the Illinois Power Agency Act. At any time, the
Ombudsperson may issue a report to the Commission detailing
any suspected violations of this Act or rules adopted by the
Commission under this Act concerning interconnection processes
or a particular interconnection.
(220 ILCS 5/23-115 new)
Sec. 23-115. Annual report. The Office shall collect and
annually report to the Commission information about net
metering under Section 16-107.5. The Office shall quantify the
totality of retail customer benefits from net metering,
including an assessment of customer value from net metering
and net metering offered under subsection (l) of Section
16-107.5.

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(220 ILCS 5/23-120 new)
Sec. 23-120. Interconnection Working Group.
(a) The Ombudsperson shall provide to the Commission with
a biennial update on consensus and non-consensus items
addressed in the Interconnection Working Group. The
Ombudsperson shall provide recommendation for Commission
actions and the proposed timing of the actions based on the
findings of the Interconnection Working Group.
(b) In collaboration with the Ethics Officer of the
Commission, the Office shall develop policies and procedures
to facilitate employees of the Office in leading the
Interconnection Working Group described in subsection (h-5) of
Section 16-107.5 without interference with docketed
proceedings. The policies and procedures developed under this
subsection shall be designed to allow the Interconnection
Working Group to work without interruption.
Section 99. Effective date. This Act takes effect upon
becoming law.
HB3758 - 419 - LRB104 12225 JDS 22331 b
INDEX
Statutes amended in order of appearance
20 ILCS 3855/1-5
20 ILCS 3855/1-10
20 ILCS 3855/1-20
20 ILCS 3855/1-75
20 ILCS 3855/1-93 new
20 ILCS 3855/1-94 new
220 ILCS 5/3-105 from Ch. 111 2/3, par. 3-105
220 ILCS 5/8-513 new
220 ILCS 5/16-102
220 ILCS 5/16-107.5
220 ILCS 5/16-107.6
220 ILCS 5/16-107.8 new
220 ILCS 5/16-107.9 new
220 ILCS 5/16-107.10 new
220 ILCS 5/16-107.11 new
220 ILCS 5/16-108
220 ILCS 5/16-111.5
220 ILCS 5/16-115
220 ILCS 5/16-136 new
220 ILCS 5/Art. XXIII
heading new
220 ILCS 5/23-101 new
220 ILCS 5/23-105 new
HB3758 - 420 - LRB104 12225 JDS 22331 b
220 ILCS 5/23-110 new
220 ILCS 5/23-115 new
220 ILCS 5/23-120 new